EPA-600/8-83-003
                                             April 1983  :
             POLLUTION CONTROL TECHNICAL MANUAL

                             FOR

               TOSCO  II OIL  SHALE  RETORTING
                  WITH UNDERGROUND MINING
                   Denver Research  Institute
                     University of  Denver
                    Denver,  Colorado  80208
                    Cooperative Agreement
                         CR. 807294
            Program Manager:  Gregory G. Ondich          '.
Office of Environmental Engineering and Technology (RD-681)
           U.S. Environmental Protection Agency
                     401 M Street, SW
                   Washington, DC  20460
             Project Officer:   Edward R.  Bates
 Industrial  Environmental  Research Laboratory - Cincinnati
                  Cincinnati,  Ohio  45268

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                                   TECHNICAL REPORT DATA
                            (Please read Instructions on the reverse before completing)
1. REPORT MO.
                              2.
                                                            3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE   '
  POLLUTION CONTROL TECHNICAL MANUAL FOR TOSCO II OIL
  SHALE RETORTING WITH UNDERGROUND MINING.
                                                            5. REPORT DATE
             6. PERFORMING ORGANIZATION CODE
7. AUTHORCS)
  Denver Research  Institute
                                                            8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
  Denver Research  Institute
  University of Denver
  Denver, Colorado  80208
             10. PROGRAM ELEMENT NO.

                 N104 CZN1A
             11. CONTRACT/GRANT NO.
                                                                CR-807294
12. SPONSORING AGENCY NAME AND ADDRESS
  Industrial Environmental Research Laboratory
  Cincinnati, Ohio   45268
              13. TYPE OF REPORT AND PERIOD COVERED
              	T7 •? n a 1 	:	
             14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT            •                                                •

       The TOSCO II  oil shale PCTM addresses  the TOSCO II retorting'technology
  as developed by The Oil Shale Corporation (a subsidiary of  the TOSCO Corporation).
  The TOSCO II oil shale facility described in this document  is  the plant-proposed
  by Colony Development Operation for commercial development  of  its,oil shale
  resources in western  Colorado.

       This manual proceeds through a description of the TOSCO II oil shale plant
  proposed by Colony Development Operation,  characterizes the waste streams produced
  in each medium, and discusses the array  of  commercially available controls
  which can be applied  to the TOSCO II plant  waste streams.   From these generally
  characterized controls, several are examined in more detail for each medium
  in order to illustrate typical control technology operation.   Control technology
  cost and performance  estimates are presented,  together with descriptions of
  the discharge streams, secondary waste streams and energy requirements.  A
  summary of data limitations and needs for environmental and control technology
  considerations is  presented.             .                          •
17.
                                KEY WORDS AND DOCUMENT ANALYSIS
                  DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TER:MS  p.  COSATl Field/Group
18. DISTRIBUTION STATEMENT
  Release to Public
                                               19. SECURITY CLASS (ThisReport)
                                                   Unclassified
                                                                          21. NO. OF PAGES
20. SECURITY CLASS (Thispage)

    Unclassified	
                                                                          22. PRICE
EPA Form 2220-1 (Ray. 4-77)   PREVIOUS EDITION is OBSOLETE
                                             411

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                                 DISCLAIMER


     The  information  in this document  has  been funded wholly or  in  part by
the United  States Environmental  Protection Agency under  Cooperative Agree-
ment CR-807294  to the  Denver Research Institute, University of  Denver.   It
has been  subject  to  the Agency's peer  and  administrative  review,  and it has
been approved for publication as an EPA document.  Mention of trade names or
commercial products does not constitute endorsement or recommendation for use.
                                     ii

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                                  FOREWORD


     The  purpose  of the  Pollution Control Technical  Manuals (PCTMs) is to
provide  process,  discharge, and  pollution control  data in summarized form
for  the  use of  permit writers,  developers,  and  other  interested parties.
The  PCTM series covers  a range  of alternate  fuel  sources, including coal
.gasification,  coal  liquefaction by direct and  indirect  processing, and the
retorting of oil shale.                                          ;

     The  series consists  of a set  of  technical  volumes  directed' at produc-
tion facilities based upon specific conversion processes.  The entire series
is  supplemented by  an appendix, volume  which  describes the  operation and
application of approximately 50 control processes.

     All   PCTMs  are  prepared on a base  plant  concept (coal  gasification and
liquefaction)  or  developers'  proposed designs  (oil  shale) which  may not
fully reflect  plants to  be built in the  future.  The PCTMs present examples
of control  applications,  both  as individual process units and as integrated
control   trains.   These examples  are  taken in  part from  applicable permit
applications and,  therefore, are reflective of specific plants.  None of the
examples are intended to convey an Agency endorsement or recommendation, but
rather are  presented for  illustrative purposes.   The  selection '.of control
technologies for application to specific plants is the exclusive function of
the designers  and permitters  who have the flexibility to utilize the lowest
cost, and/or most  effective  approaches.   It  is  hoped that  readers will  be
able to  relate  their waste streams and controls to those presented in these
manuals   to  enable  them to  better understand  the  extent to  which various
technologies may control  specific waste streams and utilize the information
in making control  technology selections for their specific needs.1

     The  reader  should be  aware  that the PCTMs  contain  no  legally binding
requirements or guidance,  and that nothing contained in the PCTMs relieves a
facility  from  compliance  with existing or  future environmental  regulations
or permit requirements.
                              Herbert L. Wiser
                    Acting Deputy Assistant Administrator
                     Office of Research and Development
                    U.S.  Environmental Protection Agency

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                                  ABSTRACT                   .   ".

              •                  - -         x    '            -  .     . '
     The  Environmental  Protection  Agency  (EPA),  Office  of  Research and
Development,  has undertaken  an extensive study  to determine synthetic fuel
plant  waste  stream  characteristics  and  pollution  control   systems.   The
purpose of this  and all other PCTMs is to convey this  information  in a manner
that is readily  useful to designers, permit writers and the public.

     The TOSCO II  oil  shale PCTM addresses the TOSCO  II retorting technology
as developed by  The Oil Shale Corporation (a subsidiary of the Tosco Corpora-
tion).   The  TOSCO II oil  shale facility described in th'is  document is the
plant proposed by  Colony Development Operation for commercial development of
its  oil  shale resources  in western Colorado.   TOSCO II plants  proposed or
built by other developers in the future can be expected to be similar in most
aspects to the plant described in this document, but  each can be  expected to
vary  in  some respects,  such  as  mining methods,  selection  of  particular
control technologies, or methods for upgrading the raw shale oil.

     This manual  proceeds through  a  description  of  the TOSCO  II oil  shale
plant  proposed 'by  Colony  Development  Operation,  characterizes  the  waste
streams produced  in  each medium,  and discusses  the array  of commercially
available controls which  can  be applied to the TOSCO  II plant waste streams.
From these  generally  characterized controls, several  are examined  in  more
detail   for  each  medium  in 'order  to  illustrate typical  control  technology
operation.   Control  technology  cost and performance estimates are presented,
together with descriptions  of the discharge streams, secondary waste streams
and energy requirements.  A  summary of data  limitations  and  needs for envi-
ronmental  and control technology considerations is presented.
                                     iv

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                                  CONTENTS

Foreword 	............... iii
Abstract	.	..!.'." iv
Figures	........[ viii
Tables	X1-
Abbreviations. ........ 	  .  	 xvii
Conversion Factors	„	xx
Acknowledgments	*  [ xxi-j
   1.  INTRODUCTION	  1
       1.1  PURPOSE	:...'-..  1
       1.2  APPROACH	  2
       1.3  DATA SOURCES	  3
       1.4  STATE OF TECHNOLOGY DEVELOPMENT.  	  ......  3
            1.4.1   TOSCO II Retorting Process .............  4
       1.5  ASSUMPTIONS.  	  	  .............  4
            1.5.1   Pollution Control and Performance Estimates. ....  5
            1.5.2   Components of Pollution Control Cost Estimates ...  5
       1.6  UNIQUE FEATURES. .	  9
       1.7  ORGANIZATION AND USE  OF THE MANUAL	  14
   2.   SUMMARY OF STUDY FEATURES  .  .	  27
       2.1  PROCESS OVERVIEW	 L  ...  28
            2.1.1   Site Description	  30
            2.1.2   Description of  the Plant  Complex	  33
            2.1.3   Description of  the Retorting Process	33
       2.2   POLLUTION  CONTROL CASE  STUDIES ...............  38
            2.2.1   Key Features  of Pollution Control	  39
            2,2.2   Pollution Control  Case Studies	  40
       2.3   SUMMARY OF  POLLUTION  CONTROL TECHNOLOGIES AND  COST .  L  ,  ...  45
   3.   PROCESS FLOW DIAGRAMS AND  FLOW RATES.  .	  53
       3.1   STRUCTURE OF  THE DIAGRAMS.  .,	  .  53
       3.2   OVERALL PLANT COMPLEX.  .  . ..'.  .  .  .  .  .....  .  .  .  .  .  .  53

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                           CONTENTS  (cont.)                   .


    3.3  UNIT PROCESS FLOW DIAGRAMS	  56

         3.3.1   Mining, Crushing and Transport of Raw Shale. ;. . . .  56
         3.3.2   TOSCO II Aboveground Retorting Process ... L ...  58
         3.3.3   Oil and Gas Recovery Unit. .  .  .	  61
         3.3.4   Amine Absorption/Claus Sulfur Recovery Units
                   (Case Studies A and B)	.:....  63
         3.3,5   Stretford Sulfur Process (Case Study C).  ......  65
         3.3.6   Wellman-Lord Tail Gas Process
                   (Case Studies A and B)	  67
         3.3.7   Hydrogen Unit	  67
     . .   3.3.8   Delayed Coker	  70
         3.3.9   Gas Oil Hydrotreater	  70
         3.3.10  Naphtha Oil Hydrotreater 	  73
         3.3.11  Ammpnia Recovery Process 	  	  75
         3.3.12  Biological Oxidation (Case Study B).  ..... i. ....  75
         3.3.13  Solid Waste Management	.........  77
         3.3.14  Water Management .	i. . . .  80

4.   INVENTORY AND COMPOSITION OF PLANT PROCESS AND WASTE STREAMS. . .  87

    4.1  INVENTORY OF STREAMS	 L ...  87

    4.2  MAJOR STREAM COMPOSITIONS.	'. . . .  125
         4.2,1   Material Balance .  .  .  .	125
         4.2.2   Raw Oil Shale	.............  125
         4.2.3   Processed Shale	130
         4.2.4   Crude Shale Oil and Upgraded Oil  Products. .....  132
         4.2.5   Retort Gas	:. . . .  132
         4.2.6   Flue Gas . .  .	  140
         4.2.7   Process Wastewaters	  146
         4.2.8   Stripped Foul Water Treatment.	 . . .  152
    4.3  -POLLUTANT CROSS-REFERENCE TABLES . .  .  .  .  .  .  .  . . ;.". . .157

5.   POLLUTION CONTROL TECHNOLOGY.	 . . . .  1S7

    5.1  AIR POLLUTION CONTROL.	  168
         5.1.1   Particulate Control.	..........  168
         5.1.2   Sulfur Control  	  ........  174
         5.1.3   Nitrogen Oxides Control	.:....  215
         5.1.4   Hydrocarbon Control.  .......'.....;....  221
         5.1.5   Carbon Monoxide Control.  . .  .  .  .  .  .  .  .'.-,. . . ..  229
         5.1.6   Control of Other Criteria Pollutants  .  .  . . ... .  230
         5.1.7   Control of Noncriteria Air Pollutants.  .......  230

    5.2  WATER MANAGEMENT AND POLLUTION CONTROL .  .  .  .  .  . . ....  233
         5.2.1   Suspended Matter, Oil  and Grease	  234
         5.2.2   Dissolved Gases and Volatiles	  243
         5.2.3   Dissolved Inorganics .....  	 .....  249

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                           CONTENTS   (cont.)

         5.2.4   Dissolved Organics	;.  .  .  .  265
         5.2.5   Water Requirements  .	.;....  290

    5.3  SOLID WASTE MANAGEMENT  .  ..................  300
         5.3.1   Disposal Approaches	,	300
         5.3.2   Surface Hydrology Control Technologies  ...'....  304
         5.3.3   Subsurface Hydrology  Control Technologies.  . .  .  .  .  311
         5.3.4   Surface Stabilization Technologies	  321
         5.3.5   Hazardous Waste Control Technologies  .........  328

6.  POLLUTION CONTROL COSTS	  331

    6.1  ENGINEERING COST DATA.  .	  331

         6.1.1   Bases of Engineering Cost Data . ..........  331
         6.1.2   Details of Engineering Costs .	  336
    6.2  COST ANALYSIS METHODOLOGY.	.	336
         6.2.1   Overview of Cost Analysis Methodology.  .......  336
         6.2.2   Economic Assumptions Used in Total
                   Cost Calculations	1   ...  343
         6.2.3   Solid Waste Management Costs	i.   .  .  .,  350
         6.2.4   Control Cost Example  . .	;   .  ,  .  351


    6.3  COST ANALYSIS RESULTS.  . 	  ........  354

         6.3.1   Results for Standard Economic Assumptions.  . .   .  .  .  354
         6.3.2   Sensitivity Analyses	  359

    6.4  DETAILS OF COST ANALYSIS METHODOLOGY	   .  .  .  377

         6.4.1   Cost Algorithms	  377
         6.4.2   Example Calculation of a Fixed Charge Factor :   .  .  .  379
         6.4.3   Cost Levelizing Calculations 	  381

7.  DATA LIMITATIONS AND RESEARCH NEEDS .	  385

    7.1  DATA LIMITATIONS ...  	  .............  385
    7.2  RESEARCH NEEDS	.............:...  386

8.  REFERENCES.  .	 .	  405

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                                    FIGURES
                                     .'•'*•'           .           '• •
 Number                      .    .   '        .;                      !

 2.1-1    Colony  Development  Operation,  site location	   31
 2.1-2    Geologic  cross  section  of  Piceance Creek Basin  	  ....   32
 2.. 1-3    Location  of overall process  activities  .	   34
 2.1-4    Plot plan for overall processing  facility	   35
 2.1-5    TOSCO II  oil shale  retorting process  ..............   37
 2.2-1    Process flow diagram, case studies A  and B	   41
 2.2-2    Process flow diagram, case study  C .  .  .	  .  .  .   42
 3.2-1    Process operations  and  waste streams	  .  .  .   54
 3.3-1    Overall plant complex.	   57
 3.3-2,    Mining and crushing.	  .  .  .	59
 3.3-3    TOSCO II  retorting  .  .	   60
 3.3-4    Oil and gas recovery  and foul water stripping.  .....  i  ...   62
 3.3-5    Amine absorber and  Claus sulfur recovery,
          case studies A and  B	64
                         . .               .            .      '     .  i
 3.3-6    Stretford sulfur recovery, case study C.  .	  .....   66
 3.3-7    Wellman-Lord process, case studies A and  B .	  i  .  .  .   68
 3.3-8    Hydrogen  unit.  .	 ..............;...   69
 3.3-9    Delayed coking	   71
 3.3-10   Gas oil  hydrogenation.  . .	  ......;.....   72
 3.3-11 .  Naphtha hydrogenation	  .' .	   74
 3.3-12  Ammonia recovery ....	   76
 3.3-13   Biological oxidation, case study B		78
3.3-14   Solid waste disposal		   79
3.3-15  Water management		81
3.3-16  Overall  water management scheme, case study A	,..:...   83
3.3-17  Overall .water management scheme, case study B	   84
3.3-18  Overall  water management scheme, case study C	•.••'.  .  .   85
                                    vin

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                              FIGURES   (cont.)
Number                                                                   Page

5.1-1   Particulate control technologies	169
5.1-2   Cost of participate control with  baghouses	  .  177
5.1-3  . Cost of participate control with  venturi wet scrubbers  ......  178
5.1-4   Sulfur dioxide control technologies.  .	'. .  .  .  180
5.1-5   Hydrogen sulfide control technologies.	  186
5.1-6   Cost of acid gas removal with DEA process.  .......;....  201
5.1-7   Cost of sulfur recovery with Glaus process	......  202
5.1-8   Cost of Claus tail gas treatment with
          Wellman-Lord process	  203
5.1-9   Cost of sulfur recovery with Stretford process	  204
5.1-10  Scot process flow scheme	  .	206
5.1-11  Cost of Claus tail gas treatment with Scot process  .......  210
5.1-12  MDEA process flow scheme 		  211
5.1-13  Cost of acid gas removal and tail gas treatment
          with MDEA Process	  214
5.1*14  Nitrogen oxides control technologies  	 ....  218
5.1-15  Hydrocarbon control technologies  	 . 	 ....  223
5.1-16  Cost of hydrocarbon control with thermal oxidizer.  . .   . . .  .  .  228
5.1-17  Carbon monoxide control technologies  	  	 ....  231
5.2-1   Suspended matter, oil and grease control technologies.   . •» .  .  .  235
5.2-2   Cost of river water clarification. ....,......,,..  240
5-. 2-3   Cost of oil/water separation	I ...  242
5.2-4   Cost of equalization pond.	-.. ............  245
5.2-5   Dissolved gases and volatiles control technologies  . .   . '. .  ...  246
5.2-6   Cost of foul water steam stripping	••,....  251
5.2-7   Cost of ammonia recovery with Phosam-W process 	 ....  255
5.2-8   Dissolved inorganics control technologies. . 	 ....  256
5.2-9   Cost of boiler feedwater treatment with zeolite resin.   . '. '.  .  .  262
5.2-10  Cost of cooling water treatment. . . .... .  .  .  . .   . . .  .  .  264
5.2-11  Flow scheme for solar evaporation treatment. .  .	  266
5.2-12  Cost of solar pond ...... 	  	  .......  267
5.2-13  Dissolved organics control  technologies.  ............  268
                                     ix

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                               FIGURES  (cont.)
 Number                                      .
                 •  '             . ,         ' •     '             '.     !
 5.2-14   Cost  of  orgam'cs  control with biological  oxidation  ........ 277
 5.2-15   Reverse  osmosis process  flow scheme.  ...	   278
 5.2-16   Cost  of  organics  removal with reverse osmosis	  ....   281
 5.2-17   Vapor compression evaporation process flow  scheme.  .......   282
 5.2-18   Cost  of  organics  control with vapor
          compression evaporation	   285
 5.2-19   Carbon adsorption process  flow scheme	   286
 5.2-20   Cost  of  organics  control with carbon  adsorption	  .  .  .  .   289
 5.2-21   Wet air  oxidation process  flow scheme	 .........   291
 5.2-22   Cost  of  organics  control with wet air oxidation	  ....   294
 5.3-1    Surface  hydrology control  technologies	  .  .  .   305
 5.3-2    Runon  diversion costs	308
 5.3-3    Typical  runoff collection  systems	   309
 5.3-4    Runoff collection  and channeling	   310
 5.3-5    Runoff collection  costs	   312
 5.3-6    Runoff/I eachate pond costs .  .  .  . .  .  .	;.  .  .  .   313
 3,3-" 7    Runoff/I eachate pond liner costs	   314
 5.3-8    Subsurface hydrology control  technologies	,.:....   316
 5.3-9    Liner  costs.	,	   319
 5.3-10   Leachate collection costs	   320
 5.3-11   Groundwater collection costs  ........ 	 ....   322
 5.3-12   Surface  stabilization technologies	   323
 5.3-13   Dust control costs .  .  .  .	325
 5.3-14   Reclamation and revegetation costs 	 ..........   327
 5.3-15  Hazardous waste control technologies  .  .  .	 ......  329
6.0-1    Interrelationships among various cost and
          economic terms ..............	  332
6.3-1   Sensitivity analyses  for case study A:  total air
          pollution control costs.  .  . .................  369
6.3-2   Sensitivity analyses  for case study A:  total water
          pollution control and solid waste management costs .  . i  . . .  370

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                                   TABLES





Number




1.5-1    Performance Levels Estimated for Major

1. 5-2
1.5-3
1.5-4

1.6-1
1.6-2

1. 7-1
2.1-1

2.3-1
2.3-2
2.3-3
4.1-1
4,1-2
4. 1-3
4.1-4
4.1-5.
4.1-6
4.2-1
4.2-2
4.2-3
4.2-4
4.2-5

4.2-6
4.2-7
Pollution Controls 	 	
Components of Fixed Capital Cost Estimates 	 	
Components of Direct Annual Operating Cost Estimates. . .
Summary of Major Standard Economic Assumptions Used
in Control Cost Evaluations 	 	 	
Major Features of the Oil Shale PCTMs 	 '.
Pollution Control Technologies Examined in the Oil
Shale PCTMs 	 	 :.
Composite List of Streams 	 	
Major Parameters Defining the Size of the Commercial
Plant Complex 	 	
Summary of Pollution Control Technologies 	 ,
Inventory of Major Pollution Control Technologies .......
Pollution Control Cost Summary 	 	
Inventory of Gaseous Streams 	 	
Compositions of Gaseous Streams 	 	 • . . ,. .
Inventory of Liquid Streams 	 ...........
Compositions of Liquid Streams 	 	
Inventory of Solid Streams. . 	 	 	 	 	 .
Compositions .of Solid Streams 	 	 '. . L .
Gross Material Balance for TOSCO II Retort. . ... . . . .
Organic Composition of Raw Shale. 	 	 , '.
Approximate Mineral Analysis of Raw Oil Shale .....;.
Trace Elemental Analysis of Raw Shale 	 	 : .
Laboratory Column Leachates from Some Colorado
Raw Oil Shales. 	 	 	
Reported Analysis of TOSCO II Processed Shale .......
Composition of Processed Shale. 	 	 	 	 	
. . . 6
. . . 7
. . . 8

. . . 9
. . . 10

. . . 12
. . , 16

. . ... 29
. . . 46
. . . 47
, . . 50
, . . 88
, . . 95
, . . 108
. . 115
. . 121
. . 123
. . 126
. . 127
. .127
... . 128

. . 129
. . 130
. .131

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                               TABLES  (cont.)
Number                                                                   Page

4.2-8    Physical Properties of TOSCO II Processed Shale ........  131
4.2-9    Levels of Trace Elements Measured in Runoff and Leachates
           from Field Test Plots of TOSCO II Retorted Shale. ......  133
4.2-10   Leachable Organics in the TOSCO II Processed Shale. ......  134
4.2-11   Soluble Salts in TOSCO II Processed Shale	...:....  135
4.2-12   Properties of TOSCO II Crude Shale Oil	  136
4.2-13   Properties of Upgraded Fuel Oil from TOSCO II Crude     '
           Shale Oil	  .......... .  .  .   .  137
4.2-14   Properties of Other Products from Upgrading of                      .
           TOSCO II Crude Shale Oil. .............   . .  ...  138
4.2-15.   Composition of Retort Gas Before Treatment.  .  .........  139
4.2-16   Sulfur Content of the Amine Treated Fuel Gas.  .  .   . .   . •.  .  .   .  140
4.2-17   Estimated Compositions of C!/C2 and C3/C4 Fractions .......  141
4.2-18   C±/C2 Fraction Retort Gas After Amine Process .........  142
4.2-19   Cx/Ca Fraction Retort Gas After Stretford Process  ...>...  143
4.2-20   C3/C4 Fraction Retort Gas After Amine Process .  	  144
4.2-21   C3/C4 Fraction Retort Gas After Stretford Process  . .   . '.  .  .   .  145
4.2-22   Calculated Flue Gas Compositions for Fuels Burned  in
           the Colony Plant, Case Studies A and B.	  147
4.2-23   Calculated Flue Gas Compositions for Fuels Burned  in
           the Colony Plant, Case Study C.  .......'..-	148
4.2-24   Materials Balance for the Glaus Unit,  .	  149
4.2-25   Materials Balance for the Wellman-Lord Unit	•  •   •  150
4.2-26   Inorganic Species in TOSCO II Foul Water. ...........  151
4.2-27   Organic Content of Gas Condensate (Foul  Water)	 ....  152
4.2-28   Composition of Foul Water	 ....  153
4.2-29   Material Balance Around Foul Water Steam Stripper  . .   ....  -   •  154
4.2-30   Material Balance Around Ammonia Recovery Unit,          :•
           Case Studies A and B	 r   .....  155
4.2-31   Material Balance Around Ammonia Recovery Unit,
           Case Study C.  . . .  .  . . . . .  .  .  .	   .  156
4.2-32   Composition of Foul Water After Biological Oxidation.   . .  .  .   .  158
4.3-1    Pollutant Cross-Reference for Gaseous Streams .........  159
4.3-2    Pollutant Cross-Reference for Liquid Streams.  .  .	  162

             .                        xi i

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                               TABLES  (cont.)
Number                                                           ,

4.3-3    Pollutant Cross-Reference for Solid Streams 	 ....  165
5.1-1    Key Features of Particulate Control Technologies. .......  170
5.1-?    Particulate Control Equipment and Design Parameters ......  175
5.1-3'   Cost of Particulate Pollution Control	,.•.•.'.'.  176
5.1-4    Total Particulate Emissions from the Plant. ..........  179
5.1-5    Key Features of Sulfur Dioxide Control Technologies ......  181
                                                                 i
5.1-6    Key Features of Hydrogen Sulfide Control Technologies .....  187
5.1-7    Major Items in the DEA Gas Treating Process	  . .  .  195
5,1-8    Major Items in the Claus Process	 :.  ...  196
5.1-9    Major Items in the Wellman-Lord Process 	  197
5.1-10   Major Items in the Holmes-Stratford Process 	  199
5.1-11   Cost of Sulfur Pollution Control.  .......;.......  200
5.1-12   Materials Balance for the Claus Process	......  207
5.1-13   Materials Balance for the Scot Process.  ............  208
5.1-14   Major Items in the Scot Process 	  .........  209
5.1-15   Retort Gas Composition Before and After MDEA Treatment. .  . .  .  212
5.1-16   Major Items in the MDEA Process	,.  . .  .  213
5.1-17   Total S02 Emissions from the Plant	  216
5.1-18   Key Features of Nitrogen Oxides Control  Technologies.  .....  219
5.1-19   Total NOx Emissions from the Plant.  .....  	 ,  . .  .  222
5.1-20   Key Features of Hydrocarbon Control  Technologies. .......  224
5.1-21   Major Items in the Thermal Oxidizer ..............  226
5.1-22   Hydrocarbon Control Practices and Equipment .  .  . . .  . .  . .  .  226
5.1-23   Cost of Hydrocarbon Pollution Control 	 ....  227
5.1-24   Total Hydrocarbon Emissions from the Plant	  229
5.1-25   Key Features of Carbon Monoxide Control  Technologies.  ....  .  232
5.1-26   Total CO Emissions from the Plant ...  .  . .  .  . r ......  233
5.2-1    Key Features of Control Technologies for Suspended
         1  Matter, Oils and Greases.	  236
5.2-2    Design and Cost of River Water Clarification.  .  . 	 .  .  239
5.2*3    Design.and Cost of API Oil/Water Separator for Foul Water . .  .  241

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                   -            TABLES  (cont.)
Number                                            '
5.2-4    Design and Cost of API Oil/Water Separator for

5.2-5
5.2-6

5.2-7
5.2-8
5.2-9
5.2-10

5.2-11
5.2-12
5.2-13
5.2-14

5.2-15

5. 2-16

5.2-17

5. 2-18

5.2-19

5.2-20
5.2-21

5.2-22
5.2-23 ;

5.2-24
5.2-25
5.2-26
5.2-27

Runoffs and Leachate 	 	
Design and Cost of Equalization Pond. ...........
Key Features of Control Technologies for Dissolved
Gases and Volatiles 	 ......
Design and Cost of Foul Water Stripper. 	 	 .
Design of Ammonia Recovery System ...........;..
Cost of Ammonia Recovery. 	 	 :. .
Key Features of Control Technologies for Dissolved
Inorganics 	
Design and Cost of Boiler Feedwater Treatment . . . . . . .
Design and Cost of Cooling Water Treatment 	 	 .
Design and Cost of Solar Evaporation Pond 	 	 .
Key Features of Control Technologies for Dissolved
Organics. 	 	 . .
Design and Cost of Biological Oxidation of Stripped
Foul Water 	 	 	 	 .
Composition of Stripped Foul Water Before and
After Reverse Osmosis Treatment 	 	
Design ahd Cost of Reverse Osmosis Treatment of
Stripped Foul Water 	 	
Composition of Foul Water After Vapor Compression
Evaporation Treatment ........ 	 i .
Design and Cost of Vapor Compression Evaporation
of Stripped Foul Water 	
Material Balance for the Carbon Adsorption Process. . . . .
Design and Cost of Activated Carbon Adsorption for ]
RO or VCE Treated Water 	 	 	 	 : ;
Material Balance for the Wet Air Oxidation Process. ..''..
Design and Cost of Wet Air Oxidation of RO and VCE
Concentrate Streams 	 ..........
Steam Production, Uses and Boiler Feedwater Needs . . . . .
Water Quality Parameters for Boiler Feedwater 	 '. .
Plant Cooling Water Requirements 	 	 ^ .
Water Quality Parameters for Cool ing. Tower
Recirculation 	 	
. . 243
. . 244

. . 247
. . 250
. . 252
. . 254

. . 257
. . 261
. . 263
. . 265

. . 269

. . 276

. . 279

. . 280

. . 283

. . 284
. . 287

. . 288
. . 292

. . 293
. .295
. . 296
. . 296

. . 297
                                    XIV

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                               TABLES   (cont.)
Number                                                           ;        Page

5.2-28   Water Requirements for Processed Shale Disposal         i
           and Dust Control.	I.  ...  298
5.2-29  'Potable and Service Water Requirements	  299
5.3-1    Major Wastes Produced Over a Period of 20 Years  .  . .  .;.  ...  301
5.3-2    Key Features of.Solid Waste Disposal Approaches  ........  302
5.3-3    Key Features of Surface Hydrology Control               ;
           Technologies.	.:..-..  306
                                                                 i
5.3-4    Key Features of Subsurface Hydrology Control            :
           Technologies		  317
5.3-5    Key Features of Surface Stabilization Technologies. ......  324
5.3-6    Key Features of Hazardous Waste Control Technologies.  .....  330
6.1-1    Detailed Engineering Costs for Air Pollution Controls  .  .  . .  .  337
6.1-2    Detailed Engineering Costs for Water Pollution          !
           Controls, Case Study A.	  338
6.1™ 3    Detailed Engineering Costs for Water Pollution          :
           Controls, Case Study 8. ......'	'..  . .  .  339
6.1-4    Detailed Engineering Costs for Water Pollution
           Controls, Case Study C	;.  . .  .  340
6.1-5    Engineering Costs and Timing of Solid Waste
           Management Activities	  341
6.2-1    Summary of Standard Cost and Economic Assumptions  . .   .  .  . .  .  344
6.2-2    Economic Assumptions that Vary from Control to Control.  ....  345
6.2-3    Fixed Capital  and Direct Annual Operating Costs
           for Solid Waste Management.	  .  . .   . l.  . .  .  352
6.2*-4    Per-Barrel Cost Breakdown for DEA Unit.  ............  353
6.3-1    Summary of Pollution Control Costs for Standard
           Economic Assumptions	 .   .  .  . .  .  356
6.3-2    Pollution Control  Costs,  by Control  Group, for          '.
           the Standard Economic Assumptions .  .  .  . .  ... ...  . .  .  357
6.3-3    .Control  Groupings	  358
6.3-4    Details  of Air Pollution Control Costs,
          • Standard Economic Assumptions .  ...............  360
6.3-5    Details  of Water Pollution Control  Costs,                ,
           Standard Economic Assumptions 	  	  ...  361
6.3-6    Details  of Solid Waste Management Costs,
           Standard Economic Assumptions ............ |.  ...  363
                                     xv

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                               TABLES  (cont.)
Number                                 .

6.3-7    Assumptions for Sensitivity Analyses. . . 	 ......  364
6.3-8    Charge Rates for Sensitivity Analyses . . 	 ......  365
6.3-9    Sensitivity Analyses Expressed as a Percentage
           of Shale Oil Value	:. .  . .  366
6.3-10   Sensitivity Analyses by Control  Group .........;....  367
6.4-1    Example of Fixed Charge Factor Calculation.  .  .  .  . .  . . .  . .  380
7.1-1    Data Limitations and Research Needs .	 .  .    388
                                    xvi

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                      ABBREVIATIONS
°API      — gravity (American Petroleum Institute)
ACF       — actual cubic feet
ACFM      — actual cubic feet per minute
ACRS      — accelerated cost recovery system
ADA       — anthraquinone disulfonic acid
ADR       — asset depreciation range
AMB       — ambient
BOD       — biochemical oxygen demand
BP        — annual by-product credit
BPSD      — barrels per stream day
CA        — carbon adsorption
CC        — total annual capital charge
CMLRB     — Colorado Mined Land Reclamation Board
COD       —chemical oxygen demand
CPB       — per-barrel control cost
CS/SS     — carbon steel/stain!ess steel
DCF       -- discounted cash flow
DCF ROR   — discounted cash flow rate of return
DEA       — diethanolamine
DGA       -- diglycolamine
DIPA      — diisopropanolamine
DOC       — direct annual operating cost
DRI       — Denver Research Institute
ED        — electrodialysis
EIA       — Environmental Impact Analysis
EIS       — Environmental Impact Statement
ESC       — annual extra start-up costs
ESP       — electrostatic precipitator

                          xvii

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                 ABBREVIATIONS   (cont.)

 FCC        —  fixed  capital cost
 FGD        —  flue gas desulfurization
 FGR        —  flue gas recirculation
 fpm        —  feet per minute
 gpm        —  gallons per minute
 gpt        —  gallons per ton
 HP         —  horsepower
 IBP        —  initial boiling point
 IOC        —  indirect annual operating cost
 ITC        —  investment tax credit
 LHV        —  low heating value
 LPG        —  liquefied petroleum gas
 LTPSD      —  long tons per stream day
 MDEA       — methyldiethanolamine
 MEA        — monoethanolamine
 MEB        -- multiple effect boiling
 MMBtu      — million British thermal units
 MSF        — multistage flash
 MTPSD      — metric tons per stream day
 MW         — megawatts
 MWt        — molecular weight
 pcf        — pounds per cubic foot
pCi/1      — picocuries per liter
 PCTM      ~ Pollution Control  Technical  Manual
 POM       — polynuclear organic matter
ppmv      — parts per million,  by volume
ppmw      — parts per million,  by weight
PSD       ~ Prevention of Significant Deterioration
psia      — pounds per square  inch, absolute
psig      — pounds per square  inch, gauge
RF        — fixed capital  charge rate
RHC       — reactive hydrocarbons
RO        — reverse osmosis

                          xviii

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                 ABBREVIATIONS  (cont.)                ;

RSH       — alky! thiols, mercaptans                  j
RW        — working capital charge rate
SCF       — standard cubic foot
SCFM      — standard cubic feet per minute
SCOT      — Shell Claus Off-gas Treating
SCR       — selective catalytic reduction
SEA       — standard economic assumptions             ,
SNPA/DEA  -- Societe Nationale des Petroles d'Aquitaine/
               diethanolamine                          :
SS        — stainless steel
STC       — annual severance tax credit               ;
SWEC      — Stone and Webster Engineering Corporation
TC        — total annual control cost
TDS       — total dissolved solids
TIA       — annual property tax and insurance allowance
TOC       — total annual operating cost
TPM       — total particulate matter
TPSD      — tons per stream day                       i
TSS       — total suspended solids
UF        — ultrafiltration
USBM      — U.S. Bureau of Mines
VCE       — vapor compression evaporation
VOC       — volatile organic compounds
WAO       — wet air oxidation
WC        — wprking capital
WPA       — Water Purification Associates
                           xix

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                           -  CONVERSION FACTORS
1 pound, 1b


1 ton

1-inch, in

1 foot, ft


1 mile,-mi


1 square inch, in2

1 square foot, ft2

1 square mile, mi2


1 acre


1 cubic inch, in3

1 cubic foot, ft3

1 gallon, gal


1 barrel, bbl            •


•1. acre-foot

1 pound/square inch, psi



1 pound/cubic inch, lb/in3
=  453.5924 grams, g
   0.4536 kilograms, kg         .
                                i
=  0.9072 metic tons, tonnes

=  2.5400 centimeters, cm

=  30.4800 centimeters, cm
   0.3048 meters, m

=  1,609.3440 meters, m
   1.6093 kilometers, km

=  6.4516 square centimeters, cm2

=  0.0929 square meters, m2

=  2.5900 square kilometers, km2
   258.9988 hectares, ha

=  4,046.8564 square meters, m2
   0.4047 hectares, ha

=  16.3871 cubic centimeters, cm3

=  28.3161 liters, 1

=  3.7853 liters, 1             :
   0.0038 cubic meters, m3

=  158.9828 liters, 1
   0.1590 cubic meters, m3      ;

=  1,233.4818 cubic meters, m3 • ,

=  70.3070 grams/square centimeter, g/cm2
   0.0680 atmospheres, atm
   0.3591 millimeters of mercury, mm of Hg

=  27.6799 grams/cubic centimeter, g/cm3
   27.6807 grams/milliliter, g/ml
                                     xx

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                         CONVERSION FACTORS  (cont.)
1 pound/cubic foot, pcf, lb/ft3  =


I gallon per ton, gpt            =

1 barrel per day, BPD            =

1 gallon per minute, gpm         =

1 British thermal unit, Btu      =
   0.0160 grams/cubic centimeter, g/cm3
   16.0185 kilograms/cubic meter, kg/m3

   4.1726 liter/tonne, 1/tonne  •

   0,1590 cubic meters/day, m3/d

   0.0631 liters/second, 1/s

   251.9958 gram-calories, g-cal
   1,054.1800 joules, .J
1 million British thermal units,
    MMBtu

1 British thermal unit/pound,
    Btu/lb

1 British thermal unit/cubic
    foot, Btu/ft3
=  292.8750 kilowatt-hours, kW-hr
=  0.5556 gram-calories/gram, g-cal/g
=  8.8994 gram-calories/liter, g-cal/1
                                     xxi

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                               ACKNOWLEDGMENTS


     This Pollution  Control  Technical  Manual was prepared for the EPA by the
Denver  Research  Institute  (DRI),  University of  Denver, Denver,  Colorado,
under  EPA   Cooperative   Agreement  CR-807294.    Subcontractor  support  was
provided  to  DRI .by  Stone and Webster  Engineering Corporation  (SWEC)  of
Denver,  Colorado,  and Water  Purification  Associates  (WPA) of  Cambridge,
Massachusetts.  The project manager for DRI was Mr.  Kishor Gala,  Chemical and
Materials Sciences Division.      "                              .
                                   xxi i

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                                  SECTION 1

                                INTRODUCTION
1.1  PURPOSE
     Future  U.S.  energy production envisions  the  development of an environ-
mentally  acceptable,  commercial  synthetic  fuels  industry.   As  part of this
overall effort, the Environmental Protection Agency (EPA), Office of Research
and Development,  has  for the past several years undertaken extensive studies
to  determine   synthetic  fuel   plant  waste   stream  characteristics  and
potentially applicable pollution control systems.

     The  purpose  of the  Pollution Control  Technical  Manuals (PCTMs)  is  to
convey,  in  a summarized  and readily  useful  manner,   information  on synfuel
waste  stream characteristics  and pollution control   technology. as obtained
from  studies by  the  EPA and  others.   The  documents provide  waste  stream
characterization  data  and describe  a wide  variety of pollution, controls  in
terms of  estimated  performance,  cost and reliability.  The  PCTMJs contain  no
legally  binding  requirements,   no   regulatory  guidance,  and ! include  no
preference  for  process  technologies  or  controls.    Nothing  within  these
documents  relieves  a  facility  from  compliance  with  existing  or  future
environmental regulations or permits.                        .    ,

     The  Pollution   Control  Technical  Manuals  consist  of  a  sbt  of  seven
discrete documents.   There are  six process specific PCTMs and a imore general
appendix  volume  which describes  over fifty pollution control  technologies.
Application  of  pollution  controls  to  a  particular  synfuel   process  is
described in each process specific manual.   The seven manuals are:

     *    Pollution Control  Technical  Manual for Lurgi Based Indirect  Coal
          Liquefaction and SNG

     •    Pollution  Control  Technical  Manual  for Koppers-Totzek  Based
          Indirect Coal Liquefaction

     *    Pollution Control  Technical  Manual for Exxon Donor-Solyent Direct
          Coal Liquefaction                                      ;

     *    Pollution  Control  Technical  Manual for Lurgi Oil Shale Retorting
          with Open  Pit Mining         .                          •

     •    Pollution  Control  Technical Manual for Modified In Situ Oil  Shale
          Retorting Combined with Lurgi Surface Retorting

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     *    Pollution Control  Technical Manual  for TOSCO  II Oil  Shale  Retorting
          with Underground Mining

     *    Control  Technology  Appendices for  Pollution Control • Technical
          Manuals                           .


     By focusing on specific process technologies, the  PCTMs attempt to  be  as
definitive as possible on waste stream characteristics  and control technology
applications.   This  focus  does  not   imply  any  EPA recommendations for
particular  process or control  designs.   Those described  in the manuals are
intended  as  representative  examples  of processes and control  technologies
that  might  be used.   The  design of  the PCTMs,  from  process description
through waste stream characterization and  control  technology evaluation,  is
intended  to  provide  the  user  with  a  comprehensive  understanding  of the
environmental factors inherent in  operating synthetic fuel plants.

     Control  technology  discussions  presented in the PCTMs reflect  pollutant
removal levels which  are believed to be achievable  with currently  available
control technologies  based  upon  existing data.  Since  there are no  domestic
commercial-scale synfuels .facilities,  the data base supporting  this  document
was  derived  from  bench-  and  pilot-scale  synfuel   facilities, developer's
estimates,  engineering  analyses  and  analogue  industries.    Ak commercial
synthetic fuel plants are built, the EPA will continue  conducting research  in
order  to  develop  a more  comprehensive  data  base.   Based on findings from
these  future  studies, the  Agency  may update these documents o;r promulgate
industry specific  standards.   In  the interim, the Agency encourages  facility
planners,  permit officials,  and other interested parties to take  advantage  of
the information contained in these documents.                     ,

1.2  APPROACH                                                    '

     The approach  taken  in  developing this manual  is to describe, in detail,
an  oil  shale .facility  which  has  been  proposed  for development and   to
emphasize its pollution  control  aspects.  This facility is the basis for the
case studies  described  in  Section 2  "Summary of  Study Features,"  Section 3
"Process  Flow  Diagrams  and  Flow  Rates,"  and  Section 4   "Inventory  and
Composition of  Plant Process  and  Waste  Streams."  The process ^descriptions
and  control   technologies  presented  in  these  case   studies   are   based   on
documents   (identified in  Section 1.3)  published  by  the proposed  -facility
developers and parallel, as  closely  as possible,  the current thinking of the
developers.

     This  manual  examines  TOSCO  II  aboveground  retorting  with underground
mining as  proposed by Colony Development Operation  for commercial development
of  its  resources  in  the Piceance Basin of  Colorado.   It should be noted,
however,  that in  May 1982  Exxon  Company,  U.S.A.  (a  subsidiary   of  Exxon
Corporation and  the  operator  for  the  Colony project)  announced that it was
halting  the  development  of  the property.   Consequently,   The Oil  Shale
Corporation (a subsidiary of Tosco Corporation and the remaining partner  in
the Colony project) decided to sell its interest in the development  to Exxon.
Future plans for development of the property are unknown at present.

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      In  order to enhance the  flexibility  of  this  manual,  and  since  oil  shale
 development   plans  are  continually  changing,  Section 5  "Pollution  Control
 Technology"  expands beyond  the description  of  the case  studies to  examine
 other pollution  control  technologies  and approaches  that may be  applicable  to
 the  waste sources identified  in the  case  studies.   While  controls applied  to
 major gaseous,  liquid,  and solid streams  described in  the case; studies are
 those which  have been  proposed by  the  developer,  Section 5 also  examines
 alternative  pollution  control  technologies on a stream-fay-stream basis.  For
 each  stream  receiving  control, all major  control  technologies are discussed,
 while some example technologies are  analyzed in considerable depth.  Stream
 flow  rates and  pollutant  characteristics  are  used in estimating  the  size,
 performance,  and cost  of the  controls,  and secondary streams  resulting  from
 the pollution control  activities are  identified.

 1.3   DATA  SOURCES

      The   plans   for   a  commercial   oil   shale  development   using   TOSCO  II
 technology were  first described  in  Colony's Environmental  Impact  Analysis
 (Colony  Development Operation, 1974).  Based on the Colony information, the
 Bureau  of  Land  Management subsequently   prepared  an Environmental Impact
 Statement  so  that Federal  action could be taken  on the proposed development
 (U.S.  DOI, 1977).   In 1977,  Colony  applied  to  the EPA  for  a Prevention  of
 Significant  Deterioration   (PSD)  permit  and  then,  in 1980,   applied to the
 Colorado  Mined Land Reclamation Board for  a  mining  and  solid waste  disposal
 permit  (Colony  Development Operation, 1977  and  March 1980,  respectively).
 These  are the principal data  sources used for the  case  studies examined  in
 this  manual.

      Other  frequently  used sources  for deriving  information  include:  "The
 TOSCO-II   Oil  Shale   Process"  (Whitcombe  and  Vawter,   March 1975),  Water
Pollution  Potential  from Surface Disposal of Processed  Oil   Shale  from the
TOSCO  II  Process  (Metcalf &  Eddy  Engineers,  October  1975),  "Analysis  of
TOSCO II  Oil  Shale Retort Water"   (Haas,  June 1979),   and   An, Engineering
Analysis  Report  on the TOSCO  II  Oil  Shale  Process   (Prien   and  Nevens,
March 1977).   Other  published as well  as  unpublished sources were  used and
 they are cited throughout the manual.

     Where available,  actual   data  from the various scale  operations in oil
 shale  processing  were  used.   It  is  believed  that  these data accurately
 reflect  the  major  technical   features  which  will  be  encouritered  in  a
commercial  oil  shale  industry.   In  addition,   technologies  from  analogue
 industries  are transferred, when  appropriate.   When  necessary,  engineering
analysis and  judgment provided by the authors of this manual (Denver Research
 Institute, Stone  and Webster  Engineering  Corporation  and  Water  Purification
Associates) and  vendor information  were used.  In each case,  all assumptions
required  to  carry out the  analyses  are listed,  and areas  lacking  hard  data
are identified (see Sections 1.5 and 7 for more detailed discussi.ons).

1.4  STATE OF TECHNOLOGY DEVELOPMENT

     As stated above, the processing plant considered in  this  manual  is based
on  the   TOSCO II   retorting   process  as.  proposed  by   Colony   Development

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Operation.  Approximately  66,000  tons  per  stream day (TPSD)  of raw shale will
be  mined using underground room-and-piliar  mining.   The shale oh  the  Colony
property has  an average oil  yield of 35  gallons  per ton (gpt) based  on  the
modified Fischer assay.   The mined shale will  be processed in is ix TOSCO  II
aboveground  retorts,  at   an  efficiency  equal  to  100%  of  Fischer assay,  to
produce  55,000 barrels  per  stream  day  (BPSD)  of  crude  shale  oil   which
eventually  will  be  converted to 47,000 BPSD  of an upgraded  syncrude.   (The
stream-day  rates  are  the  maximum, 24-hr/day  rates  that   can  be achieved;
howiaver,  occasional  equipment  failure and  required  maintenance result  in  a'
reduced  production  efficiency.   Normally,   the  plant  can  be  expected  to
operate  at 90%  of  its capacity on a  long-term basis, or for  328.5 calendar
days  per year.   Thus,  the calendar-day  production rates would be  90%  of the
stream-day  rates.)    The  current  status  of  the  retorting  technology  is
reviewed below.

1.4.. 1  TOSCO II Retorting  Process

     TOSCO II   is   a  proprietary   process    developed   by  Thei  Oil   Shale
Corporation.   It   is   an   indirectly   heated   retorting  process  involving
sol id-to-solid heat  transfer  between externally heated  ceramic balls and  raw
oil shale.

     Initial development  work  for  the process  was  performed  in|1955,  and  a
24 tons/day  pilot  plant  was  subsequently   built   in  1957.   'In  1964,   a
1,000 tons/day semi-works  plant was constructed  near  Parachute, Colorado, and
a  pilot-scale  room-and-pi liar  mine was  also  started.   The semi'-works plant
was operated for two years, from 1965 to 1967, to  demonstrate the  feasibility
of  the  process.   Based  on information  gained during that  period, a  design
study  for a  66,000 TPSD  commercial  plant  was  undertaken  and  completed  in
1968.   Operation  of the  semi-works plant was  resumed in  1969 and continued
through  1972  to  provide  additional  data  for  the  commercial  design.  That
design still stands  as the current plan for the retorting process and forms
the basis for the environmental analyses, permits, etc.

     During  the  entire   operating  period   for   the   semi-works    plant,
approximately  290,000 tons  of  oil  shale  were  processed  to  yield  over
200,,000 barrels  of  crude  shale  oil.   Material  balances  for  the  process
indicate a possibility of  obtaining 100%  of Fischer assay  oil yield for the
commercial  plant.    Substantial  operating  data were  collected  during the
operation of the pilot and semi-works plants.                    :

1.5.  ASSUMPTIONS

     In performing a detailed analysis of the TOSCO II process and associated
operations, a number of  specific assumptions which  influence  the results of
the analysis  and  their  interpretation were  made.   The  underlying,  major
assumptions relating  to pollution  control  performance and:cost,  as  well as
the bases behind the assumptions, are summarized in this section.,

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1.5,1  Pollution Control and Performance Estimates

     In  the  process of  preparing this  manual,  applicable pollution control
technologies for different waste streams were reviewed, and controls proposed
by  industry  were evaluated  to  the point that performance  and  cost could be
estimated.   Equipment  vendors'  estimates  and guarantees  were  used whenever
available.  Other performance  levels  were estimated using laboratory testing
data.  These performance  estimates should be viewed tentatively because very
little  data based   on  actual  source  testing  exist.   The major  pollution
controls  evaluated  in this  manual are presented in Table 1.5-1,  along, with
the performance levels estimated as a result of the analysis.

     The  major  air   pollution  control  technologies  (diethanolamine," or DEA,
Glaus, Wellman-Lord,  Stretford) are  commercially available and; are used in
other  industries  at  a  scale  similar  to  that  involved  in  this  manual;
therefore,  operational  difficulties  in  adapting these technologies  to  oil
shale  processing are  not expected  to  be great  and may  primarily involve
adapting these technologies to oil shale off-gas characteristics.

     In  the  area of water  pollution  control,  it has  been proposed  by  the
developer that the plant will achieve zero-discharge of the process generated
waters.   The  processing plant  will  be  water  consumptive, and the required
amount of water  will be obtained  from  outside  sources,  such as |the Colorado
River.   the  process waters  are treated  to  the  degree  necessary for reuse.
The  technologies considered  (steam  stripping,  ammonia recovery)  have been
used in  analogue  industries  and can be  expected  to  be employed successfully
in  the oil  shale industry.   Waters  used in auxiliary  plant  operations  are
also treated since  the  wastes produced  from  these operations  may be used in
processed shale  moistening and thus may become a source of pollution.  Reuse
of  some  waters  may  negate  a  need for pollution control;  in  such  cases, no
pollution controls in a conventional sense are applied.

     Solid  wastes  are  managed   using  a  controlled   surface  landfill,  as
proposed  in  Colony's   permit  application  to  the   Colorado '. Mined  Land
Reclamation  Board.    The  control  technologies  considered in  the  areas  of
surface  hydrology (e.g,, runon diversion system, runoff  collection system,
runoff  catchment  embankment),  subsurface  hydrology  (e.g.,  bottom  liner,
groundwater  collection   system),  and   surface   stabilization  (e.g., dust
suppression,  reclamation   and   revegetation)    are   traditional   practices
associated with solid waste management.

1.5.2  Components of Pollution Control Cost Estimates

     Fixed capital  and  direct annual  operating costs were estimated for each
piece  of pollution control  equipment  and  each control   activity.   These
figures were then used,  along with economic assumptions,  to calculate total
annual control costs which  include an annual charge  for capital.   The total
annual capital charge  provides  for a required after-tax return qn investment
of 12 percent.   The approach used to estimate the capital and operating costs
and the  economic  analysis techniques  applied to these data are summarized in
Tables 1.5-2 through 1.5-4.

-------
                   TABLE 1.5-1.   PERFORMANCE  LEVELS  ESTIMATED  FOR  MAJOR  POLLUTION  CONTROLS•
Control Description
Pollutant Controlled
                                        Control  Level Estimated
AIR POLLUTION CONTROL
Baghouses
Water Sprays
Foam Sprays
Thermal Oxidizer
High Energy Venturi Wet Scrubber
Venturi Wet Scrubber
  Ball Elutrlator
.  Processed Shale Moisturizer
Diethanolaroine (DEA) Gas
  Treating Process
Glaus Sulfur Plant
Wellman-Lord Tail Gas Unit
Holmes-Stretford Gas Treating
  Proce.ss

WATER POLLUTION CONTROL
Foul Water Stripper
Ammonia Recovery Unit
Biological Oxidation

SOLID WASTE MANAGEMENT
Surface Landfill
Raw and Processed Shale Dust
Raw and Processed Shale Dust
Raw and Processed Shale Oust
Hydrocarbons
Raw Shale Dust

Processed Shale Dust
Processed Shale Dust
H2S                '

H2S
H2S
H2S
NH3
H2S
Organic Matter
NH3
BOD
TOC
Processed Shale, Coke, Sludges,
  Slowdowns, Concentrates, Spent
  Catalysts, etc.
99.7%
50%
85%
85%  ..
99.8%
           = 30" of water
99.8% @ AP = 40" of water
          |
98.4% AP = 20" of water
135 ppmv

95%
92%
30 pprnv3  i
94%b
99%b
50%b
99.4%b
90%b
45%b
                                         N/A
  Based on Peabody Process Systems, Inc., February 1981.
                                                                                           ,|
  Estimates from treatability studies on similar waters conducted by Water Purification Associates,
  unpublished.
Source:   Colony Development Operation, 1977, except as noted.

-------
     Fixed  capital  and direct annual operating cost estimates were developed
on  a component  basis,  using current cost  data.from  the actual ' installation
and  .operation  of  similar  facilities  and  using  vendor  quotes  for major
equipment  items.   Capital  cost  estimates  are  expected to  have an  average
accuracy  of ±30 percent.   This  level  of accuracy can only bei verified by
actual  equipment  installation.    Experience   in  using  the  cost estimating
procedures  for  units  which actually  have  been  constructed  and operated
indicate  that  this  level   of  accuracy  should  be achievable  :if  the- unit
installed  is  exactly as  described in  determining the cost estimate.   Any
design changes  could cause the actual installed capital cost to:fall  outside.
the  range.                                                       :
     Table 1.5-2  lists  the components  estimated in determining the installed
fixed capital cost of pollution control equipment.  For  simple equipment, all
components  may  not  be present.   For large  and complex equipment, estimating
the  cost of each component may be a major effort.  A descriptioniof the major
equipment included  in each capital cost estimate is provided infection 5 of
this document.                                                    :

          TABLE 1.5-2.  COMPONENTS OF FIXED CAPITAL COST ESTIMATES
                                 Components
               Major Equipment (vendor quotes)
               Site Preparation, Excavation and Foundations
               Concrete and Rebar
               Support Structures
               Piping, Ductwork, Joints, Valves, Dampers, etc.
               Duct and Pipe Insulation
               Pumps and Blowers
               Electrical    .
               Instrumentation and Controls
               Monitoring Equipment
               Erection and Commissioning
               Painting
               Buildings
               Engineering and Other Indirect Costs
               Contractor's Fee
               Contingency Allowances

Source:   DRI.

-------
      Table 1.5-3  shows  the  components  comprising  direct  annual   operating
 costs.   Operating supplies  include  such items as baghouse bags.. Maintenance
 includes  the  cost  of parts used,  but  the  needed  inventory  of replacement
 parts is  included in  fixed capital  cost.  The  cost of water consumed  is  not
 included  due  to  uncertainties  in  estimating  the  value  of water.   Direct
 annual  operating costs do not include by-product credits; however, by-product
 credits are  included  in  total  annual operating  costs.   The operating costs
 (direct,  indirect  and  total)  for  each  pollution  control,   along wvth  a
 detailed  discussion of  how the  costs  were determined,  are presented on  a
 component basis  in Section 6.
      TABLE  1.5-3.   COMPONENTS OF DIRECT ANNUAL OPERATING COST ESTIMATES
                                                                ,  i
  .--,_ -	L-iu-MiL.Mjii-ai.i--  -..-.  _._--,	ri" -.-  ..-; i i	--. '   	     	_. -   IB--,-.-ii..iiv   ....... J. _..-'-  ....;'. L _.'...--

                                  Components                      !

                Maintenance and Maintenance Supplies

                Operating  Supplies                                ;
                                                                  i
                Operating  Labor                                   :

                Cooling  Water

                Steam                                              :

                Electricity

                Fuel Gas and Oil

                Indirect Costs  (e.g.,  supervision,  laboratory, etc.)*


*  Indirect costs are included  in the Tabor rate.

Source:  DRI.                                                     •'.     '
                     /           •                    •
     Table 1.5-4  presents  the  major  economic  assumptions  used  in the  cost
evaluations.   Most economic  assumptions  have  been  standardized so that the
results found  in  all  of the  oil  shale PCTMs may  be  compared.  A sensitivity
analysis was performed (see Section 6  "Pollution Control  Costs")  to determine
the effects  of changes in some  of  the standard economic  assumptions.   These
changes  include  delayed  start-up,  changing  capital  and  operating  costs,
financing  considerations  and others.   All  of the  oil  shale  PCTMs  use  a
discounted cash flow approach (DCF).and constant dollars  (mid-1980).

-------
       -  TABLE 1.5-4.   SUMMARY OF MAJOR STANDARD ECONOMIC ASSUMPTIONS
                       USED IN CONTROL COST EVALUATIONS
                                 . Assumptions3
 *    Approach:   Discounted Cash Flow Evaluation (DCF)

 •    Method:   Revenue.Requirement determined from capital  charge plus
        operating cost

 »    Required  DCF ROR:   12% (100% equity basis)

 *    Cost  Base:   Mid-1980  constant dollars

 *    Income Tax:   In  accordance with current regulations  (48% combined tax
        rate, 20% investment tax credit);  tax credits  and  allowances  can be
        passed  through to a parent company that  can benefit from  them
        immediately, without waiting for  the  project to  become profitable

 *    Project Timing:   4  years  construction,  20  years  life

 •    Normal Plant Output:   47,000 barrels per stream'  day  (net, after
        in-plant  use)

 «•    Operating Factors:    Year 1      -  50%
                           Year 2      -  75%
                           Years  3-20  -  90%


 a A more detailed list of  assumptions  is  presented in Section 6,.Table 6.2-1.

  This method permits accurate costs to  be determined separately:for each
  control  using the DCF  approach,  without the need for  an  estimate of total
 . plant cost.                                .

 Source:  DRI.
1.6  UNIQUE FEATURES

     Three  oil  shale  retorting  processes  were  selected for  the  oil  shale
PCTMs  to  allow  consideration  of  different types  of  retorting processes,
mining  and disposal  techniques,  and  pollution  control  technologies.   Some
features  are  found in  more than  one  manual, but  each  process examined has
important unique features which are listed in Table 1.6-1.

     Table 1.6-2  lists  the  pollution  control  technologies examined  in the
three PCTMs.  The table is designed to assist the reader  in locating detailed
information on any specific control technology.                   '

-------
             TABLE  1.6-1.   MAJOR  FEATURES  OF  THE  OIL  SHALE  PCTMs
                                                       PCTMs
 Feature
TOSCO II    MIS-Lurgi    Lurgi-Open Pit
MINING

Underground
   Room-and-Pillar

Underground MIS

Open Pit


RETORTING

Aboveground

Underground

Direct'heated

Indirect-heated

Solid-to-Solid
   Heat Transfer

Gas-to-Solid
   Heat Transfer

Resource Recovery
   from Processed Shale

High Carbon Processed Shale

Low Carbon Processed Shale

Raw Shale Preheating


PROCESSING

High Btu Off-gas

Low Btu Off-gas

Oil Fractionation
   X


   X
X

X

X

X


X


X


X
                X

               .X

                X
X


X
                                                         (Continued)
                                     10

-------
                            .TABLE.1.6-1  (cont.)
                                                      PCTMs
Feature                              TOSCO II    MIS-Lurgi    Lurgi-Open Pit

PROCESSING (cont.)

Qi1 Upgradi ng                           X

Gas Upgrading (for sale)                X                           X

In-Pi ant Fuel Use                       X            X           •

Excess Electricity            .                       X


POLLUTION CONTROL              .                                         .

Retort Gas Cleanup                      XX              X

Process Water Cleanup                   X            X              X

Excess Water Discharge                                           ;   X

By-product Recovery                     X            X      '     >   X


WASTE DISPOSAL              .                                     ;

Surface Landfill                        X            X

Permitted Design                    .X

Open Pit Backfill  ,                                              i   X

Groundwater Contamination                                        •
  Potential (subsurface
  disposal or retort abandonment)                    X              X

Surface Water Contamination
  Potential (valley fill)               X            X           ;


Source:  DRI.
                                     11

-------
TABLE 1.6-2..  POLLUTION CONTROL TECHNOLOGIES EXAMINED
               IN THE OIL SHALE PCTMs
Control Technology
AIR POLLUTION
Diethanolamine (DEA)
Methyl diethano lamina (MDEA)
Glaus
Wellman-Lord
Stratford
Shell Claus Off -gas
Treating (SCOT)
Limestone Scrubber (FGD)
Absorber/Cooler
Low Flare
High Energy Venturi Wet Scrubber
Venturi Wet Scrubber
Electrostatic Precipitator
Thermal Oxidizer
Fabric Filter (baghouse)
Foam Sprays
Water Sprays
Doubl e Seal Oil Storage
Refrigerated Ammonia Storage
Catalytic Converter
Maintenance
PCTMs i
TOSCO II MIS-Lurgi Lurgi-Open Pit
X
X ;
x :
X . i
X X > X
* !
• x •
I
. . X ' !
X
1
x • .';
X • ' ' :
x x !
x x
X •
X X ' X
x x x
x x . . •'! x
X X X
i
x x : x
x x • ' x ' .
x x ; x
                                            (Continued)
                        12

-------
TABLE 1.6-2  (cont.) .
Control Technology
WATER MANAGEMENT
Ammonia Recovery
Biological Oxidation
Steam Stripper
Kettle Evaporator
Reverse Osmosis
Carbon Adsorption
Wet. Air Oxidation
Vapor Compression
Evaporation
Re inject ion
Multimedia Gravity
Filtration
Clarifier
Process Oil/Water
Separator
Runoff Oil /Water
Separator
Boiler Feedwater
Treatment
Cooling Tower
Makeup Treatment
Equalization Pond
Aerated Pond
Solar Pond

TOSCO II
X
X
X

X
X
X
X

•
x
X
X
X
X ;
X

X
PCTMs
MIS-Lurgi
X

X
X
X
X
X


X
x
X
X
X
x
X

X
i .
Lurgi-Open Pit
X
i
i

x
X
•

: X

x
X
X
X
'. x
.' X
x
X
                            (Continued)
        13

-------
                             TABLE 1.6-2  (cont.)
Control Technology
SOLID WASTE MANAGEMENT
Runoff Collection System
Upper Embankments
Lower Embankments
Runon Collection System
Stilling Basin
Water Impoundment
Leachate Collection System
Spring Collection/Underdrains
Covers and Bottom Liners
MIS Spent Retort Treatment
Dust Supression
Surface Reclamation
Piezometers

. TOSCO II

X
X
X
X
X
X
X
x.
X

x
x
-
PCTMs
MIS-Lurgi Lurgi-Open Pit
i
X X

X
X


X :
x , :
x • •'•• x
x
X ' i X
X X
i
' .'• X
Source:  DRI.
1.7  ORGANIZATION AND USE OF THE MANUAL
                                                               • i

     Following this  "Introduction"  to  the PCTM are  six  major sections which
present  material  ranging  from  basic  background  information  to  detailed
pollution  control  data and  costs.   In  addition,  a complete  listing  of all
information  sources  used  to develop  the  manual  is  provided in  Section 8
"References."  A brief description of each of the major sections;is presented
below.

     Section 2 provides an overview of the TOSCO II retorting process and the
case studies examined  in  the manual.   It gives background information on the
proposed  .project development,  including  the  site  involved, retorting  and
                                     14

-------
 mining processes,  and the  pollution  controls proposed by  the  developers  of
 the Colony property.

      Section 3 expands upon the case studies outlined in Section; 2.   Detailed
 process flow  diagrams  and descriptions  are given  for  each  unit  process.
 Individual  streams,  their  mass  flow  rates, and  other  characteristics  are
 generated  during the  unit process analyses,  and  this  information's  the basis
 for detailed stream discussions presented in Section  4.          ;

      Section 4  provides  the  detailed  compositions   for the  major  process
 streams identified in Section  3.   These parameters  are then  used in  designing
 and costing the  pollution  control  technologies  discussed in Section  5.  All
 streams identified in Section  3 are inventoried  by  media (gas,  liquid, solid)
 and important  features  of each  stream are  noted  (Tables  4.1-1,  4.1-3 and
 4.1-5,  respectively).  Also, the detailed  stream compositions  are summarized
 by  media (Table 4.1-2,  4.1-4 and  4.1-6).

      Section 5 presents  concise  inventories of the  available control  tech-
 nologies  and  approaches  for air,  water and  solid wastes.   Key features  of
 each technology  are  briefly   described and  many  leading  technologies are
 analyzed  in greater  depth.  The  fixed capital  and  direct  annual   operating
 costs  and  design  details  for  the  leading technologies  are also presented.

      Section 6 presents  the total  annual  and per-barrel cost of  pollution
 control  based  upon the cost data  developed  for the  control technologies  in
 Section 5  and  the standard  economic assumptions used  in all oil  shale PCTMs.
 This  section also  analyzes  the  sensitivity of the control  costs to variations
 in   the standard  economic  assumptions  and   capital  and operating cost
 parameters.                                                      :

     Section 7  discusses  the limitations  of the data base  used in .the  prepar-
 ation  of  the  manual.   It  also  identifies  important  areas  that may  require
 more research.

     Table 1.7-1  provides  a composite  list  of  the major process  and waste
 streams generated by  the facility described  in Section 3.   ATI  streams are
 identified with a unique name  and  number.  An asterisk •(*)  is placed  next to
 the  stream number  if the stream comes  into  contact with  the environment at
 any.  point  in the process,  and  a  descriptive  letter is given to identify the
 state  of  the  stream,  i.e.,  gaseous  (G),   liquid  (L)  or solid'(S).   Also,
 cross-references  are  included   for  the flow diagrams  in which  the  stream is
 produced   and/or   processed   (Section 3),    detailed  composition    tables
 (Section 4),   and   applicable   control   technologies   (Section 5')  to  allow
 tracking of  the stream from  its origin to its final  disposition. .

     For example,  stream 32 in  Table  1.7-1  is the untreated C2iand  lighter
 gases—a gaseous  stream that  does  not  contact   the  environment.    It  is
produced by  processing  of the  pyrolysis vapors (stream 17) from the TOSCO II
 retorts, as  illustrated in  Figure 3.3-4, Section 3.   Table 4.2-17 (Section 4),
provides the detailed composition  of  the gases, and  Section 5.1.2  ("Sulfur
Control")   briefly  discusses approaches  to  lower the  sulfur content  of the
gases in order to control the  sulfur emissions.   Figure 3.3-4 indicates that


       •         • '  .      •           15                          .       ' .     .

-------
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either Figure 3.3-5  (Case  Studies A and B) or Figure 3.3-6 (Case Study C)  is
the destination for the gases.

     Figure 3.3-5  exemplifies  the  processing  of  the  untreated   gases   to
produce the treated  Cg and lighter gases  (stream  33)  for which the detailed
composition is  given  in Table 4.2-18.   As a result of the treatment, a waste
gas  (acid gas  from  the  amine  system,  stream 56),  containing! most  of the
hydrogen  sulfide originally  present  in  the  untreated  gases,  'is  produced.
This  gas   can   be  followed  sequentially  through  Figures  3.3-5 (stream 57)
and: 3.3-7  (stream 82)  to  illustrate the recovery of sulfur from the acid gas
and  additional  treatment  of  ttie tail gas  before  it  is  released  into the
atmosphere.  Other  process and  waste  streams can  be followed  in  a similar
manner.                                                       .-   ! '
                                     25

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                                   SECTION 2

             .              SUMMARY OF STUDY FEATURES             I


      The  Colony  Shale  Oil  Project was initiated  in  1964 as  a joint venture of
 The   Oil   Shale   Corporation   (a   subsidiary   of Tosco  Corporation),   Sohio
 Petroleum Company,  and Cleveland  Cliffs  Iron  Company.   The  partnership  formed
 the  Colony Development Company to operate the project  on an oil  shale reserve
 known as  this "Colony  property,"  which consists  of approximately  8,800 acres
 located at the head of  Parachute Creek  Valley in Colorado.   Based on The  Oil
 Shale Corporation's previously tested TOSCO II retorting process;  a prototype
 mine and  semi-works plant were built and operated  from 1965 to  1967, and  the
 design for  a 47,000  BPSD (66,000  TPSD) commercial   plant was ' subsequently
 completed in  1968.                                               ;

      In  1969, Atlantic Richfield  Company joined  the  venture  group  as  the
 operator  and the  partnership  was renamed the Colony  Development  Operation.
 Also in  1969,  a  second  semi-works  program  was   initiated  to  provide more
 operating data on  the  process.  Based on  this  new information, the  design  and
 cost estimates  for  a  commercial  oil   shale  plant  were   updated  in   1972.
 Following this,  Colony published its  Environmental Impact  Analysis  (EIA)  for
 the  updated plant in 1974,  However,  because  of the unfavorable;economics  of
 commercial  shale  oil  production,  the  project  was suspended in 1974  and Sohio
 Petroleum  Company  and  Cleveland   Cliffs  Iron  Company withdrew  from  the
 partnership.   In  that same year,  Shell  Oil  Company   and  Ashland Oil, Inc.
 entered the Colony partnership, but  these companies withdrew from the project
 in 1976 and 1977, respectively.  The U.S.  Department  of Interior's  Bureau  of
 Land Management  had issued an  Environmental  Impact Statement (EIS) in  1977,
 but  a decision  on granting the  requested action  (right of way,  etc.) was
 deferred  because the Colony project  had been suspended  indefinitely.

      In 1980,  Exxon Corporation bought Atlantic Richfield  Company's share  in
 the  partnership  and became the operator  for  the project.  Exxon Corporation
 and  Tosco Corporation  pursued  the  development  of  the Colony property  until
 May  1982,   at  which time Exxon announced  that  it was  halting the development
 of:the project.  Consequently, Tosco  Corporation decided  to  sell :its interest
 in.the project to Exxon.  Future plans  for the  Colony  Shale Oil Project are
 unknown at present.

     Prior to this latest suspension  of the Colony project,  all  major Federal
and  state  permits  had  been issued for the proposed commercial  facility, and
the  EPA had approved  a Prevention of Significant Deterioration  :(PSD)  permit
 (July 1979)  under  the  Clean  Air  Act.    However, additional  analyses  or
statements may need to be prepared  and  new permits issued  in the event that
                                     27

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any   reactivated  p-lans   vary   significantly   from   the   originally   proposed
development.

2.1   PROCESS OVERVIEW

      The  case  studies  presented  in this  manual  are  based on  the  plans
proposed  by Colony  (i.e.,  the plans  upon which all environmental  analyses,
statements,  and  permits  have  been  issued).   The  plant operations  include
underground  mining,   TOSCO II  aboveground   retorting,   product  upgrading,
pollution control, waste  disposal and  several  auxiliary  activities.

      Mining  for the  full-scale plant will  be performed  by the underground
room-and-pillar   method.    This  technique   is   fairly  advanced   in   other
industries,  such  as  coal  and  mineral  mining.  Additionally,  the  oil  shale
zone  under the Colony property  is quite amenable to  this  type  of ;mining.  The
overburden  thickness varies  from  300 feet to  1,200 feet;  therefore,  other
mining  methods such  as  open   pit  and strip  mining are  not  suitable.  The
mineable Mahogany zone  under the property has outcropped at various places,
and  it  is  easily accessible from the  eroded  canyon walls.  Theiaverage zone
thickness  is  about  60  feet   and  the  grade  about 35 gpt.   Approximately
1,23  billion  tons of such  oil shale  are estimated to be in  place.   Some
66,000 tons of  oil  shale from  the  Mahogany  zone will  need  to be mined  daily
for  the  commercial  operation,  making this operation larger  than 'any  existing
room-and-piliar mine  in  the  world.  Crushing will  be  achieved  by  standard
crushing equipment.

      A  full-sized TOSCO II  pyrolysis unit  is  designed  to handle 11,000 TPSO
of minus  1/2 inch feed  material  on  a 24-hr/day basis;  therefore,  six such
units will  be required  for the  66,000 TPSD  of oil  shale processing.  Each
pyrolysis unit will consist of  systems for shale preheating, retorting,  shale
disposal,- product recovery and ceramic ball  heating.   The gaseous products
will   be  fractionated  and cleaned before in-plant  use or sale.  A portion of
the  shale  oil  will  be  used  as plant  fuel,  while the  remainder  will  be
upgraded  to produce  47,000 BPSD of  a light,  sweet syncrude which  will  be
pipelined  for  further  refining.    Sulfur  and  ammonia   will  be obtained  as
by-products from the pollution  control activities.

      Solid  wastes will  be disposed  of  in a  surface  landfill in  a nearby
shallow  valley,  using  procedures  required  by  the  Colorado  Mined  Land
Reclamation Board  (CMLRB).  Water for the process needs and processed shale
moisturizing  will  be  obtained  by  treatment  and  reuse  of  the  process
wastewaters and from the Colorado River.                          ,

      If fully  exploited by room-and-pillar mining,  approximately  62% of the
total  in-pTace  resource,  or  760 million  tons,  can be  recovered  from the
property (Tosco Corp.,  December 31, 1980).  At the  given  processing rate of
66,000 TPSD, the resource should last over 30 years.   However,  in. order to be
consistent  with  other  oil  shale  Pollution  Control   Technical  Manuals,  a
project life of 20 years has been used for costing purposes.

     The quantities defining the  dimensions of the  plant  complex  are listed
in Table 2.1-1.   Process  related  quantities  have been  estimated  primarily
                                                                 ! •

                                     28

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              TABLE  2.1-1.   MAJOR PARAMETERS  DEFINING THE SIZE OF
                         THE COMMERCIAL PLANT COMPLEX
 Parameter,  Unit  ;                                                Quantity
 Net Oil  Produced,  BPSD                                            47,000*
 LPG Produced, BPSD                                                4,330
 Retort Gas  Produced  (0^2  fraction,  dry  basis),  103  Ib/hr        ,   186
 Retort Gas  Heating Value  (LHV, before treatment),  Btu/lb          11,400
 Retort Gas  Heating Value  (LHV, after  treatment),  Btu/lb           22,200
 Raw Shale Processed, TPSD                                         66,000
 Raw Shale 'Grade, gpt                                                 35
 Bietorting Yield, % Fischer  Assay                               .      100
 Processed Shale Disposed  (dry basis),  TPSD                        53,400
 Processed Shale Moisturizing Water, gpm                            1,639
 Foul Water  Produced, gpm                                             498
 Sulfur Produced, MTPSD                         .                      173
 Ammonia  Produced,  TPSO                                             135-143
 Coke Produced, TPSD                                                  800
 Fuel Consumed
  Fuel Gas  (process fuel),  103 Ib/hr          ,                       80
  Fuel Gas  (reforming), 103 Ib/hr                                    40
  C4 Liquids, 10s  Ib/hr                                              27
  Gas Oil,  BPSD                                                   .4,900
 Shale Processed per Retort, TPSD                                  11,000
 Number of Retorts                                                     6
 On-stream Factor, %                                                     .
  Year 1      .        ,        "          .                       .50
  Year 2                                                             75
  Years 3-20                                       .                  90
 Project Duration, years                                              20
Total  Land Area, acres                                            8,800
Area Mined,  acres                        .                         4,100
Processed Shale Disposal Area, acres                              ,   900
Source Water Consumed, acre-feet/year  (bbl/bbl of oil) 8,420-8,540 (4.2-4.3)
* The crude shale oil production is equivalent to 55,000 BPSO, but in-plant
  use and upgrading reduce the net oil yield to 47,000 BPSD.
Source:   DRI estimates based on data from Colony Development Operation,
  . ,    '  1974.    .                        '

                                     29

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from data  published by  Colony (Colony  Development  Operation,  1974).   These
quantities  form  the  basis  for. the  technical  analyses  and : discussions
presented in the document.                                       ;

2.1,1  Site Description

     The Colony property  is located approximately 15 miles north of the town
of  Grand Valley,  Colorado, as  illustrated  in Figure 2.1-1.   The property
covers   approximately   8,800  contiguous   mineral   acres  of   Which   about
7,800 acres are believed to overlie the Mahogany oil  shale zone. •

     The  proposed  mine  and  plant complex will  be situated  in  the  Upper
Parachute Creek drainage  basin,  which is a part of the Grand division of the
Upper Colorado River Basin.   The entire Colony  property  is  drained by three
upper tributaries of  Parachute  Creek:  Davis  Gulch,  Middle  Fork  and East
Middle  Fork.   Two other  tributaries,  namely East Fork and West Fork,  drain
south of the  property  into Parachute Creek, which in turn discharges at the
north bank of the Colorado River near Grand Valley.

     The  Parachute  Creek  tributaries have cut through  the  plateau-forming
sediments to produce a network of steep-sided box canyons, in which rocky and
heavily eroded lower slopes rise sharply to meet talus slopes at the base of
oil shale cliffs.   These  canyons measure 1,000  feet  in vertical  wall  height
and in excess of 2,000 feet of total valley depths.

     Except where eroded to form the deep canyons, the entire Parachute Creek
Valley  is  underlain  by   the  Green  River  Oil  Shale  Formation,  which  is
characterized by  four  members:  the  Evacuation Creek member,  the Parachute
Creek member,  the  Garden Gulch  member,  and the  Douglas Creek  member (see
Figure 2.1-2).  The Parachute  Creek member is the most important because it
consists  of the  oil   shale.   Other  mineral  resources,  such  as  nahcolite,
dawsonite and halite,  are usually abundant in the Green River Formation, but
the core sample analysis indicates that these minerals are practically absent
on the Colony property.            .

     Surface water  supplies are  scarce,  with the exception  of the Colorado
River.   Water production  occurs  in the form of  snow and  rain throughout the
area.    In addition  to  the Parachute Creek tributaries mentioned ,above,  there
are numerous  intermittent  springs, gulches,  and arroyos  along  the  creek.
Parachute Creek runs along the valley bottom from an elevation of 6,000 feet
to below 5,000 feet.   The flow of the creek depends mainly  on springs which
emerge near or in the creek bed, and they in turn depend on groundwater which
varies with the amount of previous precipitation and  runoff.

     The water quality of Parachute Creek is lower than that of the Colorado
River.    Degradation caused  by  irrigation  and  subsequent drainage  through
salty soils result  in a  saline  water  containing  higher concentrations of
total  dissolved solids,  sodium,  magnesium,  sulfate,  etc., than are found in
the Colorado  River.  However,  the organic  content of  Parachute Creek  is low
relative to the salt content.
                                     30

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SOURCE-' ORI based on Colony  Development Operation, 1974





              FIGURE 2.1-1  COLONY DEVELOPMENT OPERATION, SITE LOCATION
                                       31

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     There  are two  known aquifers which  underlie the entire Piceance  Creek
Basin.   The  upper  aquifer is  found  in the  Evacuation Creek member of  the
formation and exists as  a zone  of  saturation  in  fractures  of the  bedrock  and
pore spaces  of the alluvium.  The  lower aquifer  exists between  the  Parachute
Creek  member and the Garden Gulch  member.  The two  aquifers are,separated by
the impervious Mahogany oil shale zone.

     The climate of  the area is  arid, characterized  by abundant  sunshine,  low
precipitation, warm  summer temperatures and low relative humidity.   The  local
climate  is  strongly  influenced by  microclimatic  features  such  as slope,
aspect', elevation, soil moisture content,  vegetation, etc.  Wind^patterns  are
highly influenced by the  local topography  but  are  prevalently west-southwest.
The  downslope of the  narrow Parachute  Creek valley  shields  local air flow
from gradient wind  flow  fields.  The shielding  effects  of the mountains  to
the west  also cause an increase in mechanically  induced turbulence  above  the
plateau.   Average temperatures  recorded  on  the  Colony property  during  the
months  of July  and  August are  68° and  67°F, respectively; in January  and
February,  averages   are   23°  and 25°F.   During  the  summer,  strong outgoing
terrestrial  radiation  provides  cool nights, while in midwinter,'Strong  solar
radiation   and  dry  air  provide   a   pleasant  environment   despite   low
temperatures.   The  vertical  temperature profiles  are  also  influenced by  the
local topography.

2-1,2  Description of the Plant  Complex

     Figure  2.1-3 shows the  relative  locations of the mine bench, processing
facilities,  and  processed shale disposal  area,on the  Colony property.    The
property is  divided  into  two sections:  Colony East and Colony ;West.   It is
the'Colony West property  for which the development is planned.   ;
                                                                 !•
     The mine  bench  will  be located on  the  upper portion of the Middle Fork
Canyon.  Entry into the mine will be through five portals on the east side  of
the  canyon   and  three  portals on  the west side.   Primary crushing will   be
performed on the bench, and the  crushed ore will be conveyed to  the  plant.   A
coarse ore stockpile will  be maintained near the plant.          .

     The processing facilities will be located on Roan Plateau,  some.900 .feet
above the mine bench and  to the west.   Figure 2.1-4 depicts a plot plan  for
the  facilities  which  will  include  six  TOSCO II  processing  trains,   or
pyrolysis units,  fine ore  crushing and storage,  product  upgrading, product
tankage, and other auxiliary facilities.
                                           •        ''    '"  .      *    • '
     The processed shale  disposal area will be located in Davis Gulch, to  the
north  of  the  processing   facilities.   The wastes  from  the plants will   be
transported  to the  disposal  area  in overland  covered  conveyors  and  then
hauled by truck to the active area of the  landfill.               .

2.1,,3  Description of the Retorting Process

     A  detailed description  of  the  TOSCO II  pyrolysis system (retorting,
preheating  and  processed  shale  removal)  is presented  below.    Section 3
                                     33

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 presents  unit  flow diagrams  describing  the operation  of other  processing
 units  in  the  integrated plant  complex.    ..

     TOSCO  II  Retorting Process--

     Figure 2.1-5 shows a conceptual  flow diagram of the TOSCO 'II  retorting
 process.  The process  is indirectly  heated and  employs  a sol id-to-solid heat
 exchange  (between hot  ceramic balls  and  raw shale) as  a means  for providing
 the heat  of retorting.

     The  integral  parts of the TOSCO II  pyrolysis  system are  retorting,  ball
 and raw shale  heating,  product recovery,  and processed shale  removal  systems.

     The  TOSCO  II  retort is a horizontal,  slightly  inclined,  rotating drum  to
 which  raw  shale  (minus 1/2-inch  size, preheated to approximately 500°F)  is
 fed..   Ceramic balls,  at 1.5 times the shale mass  flow  rate, and  previously
 heated to about 1,300°F, are also added  to the  retort.   The  rotating, mixing
 action  results in  pulverization  of  the  raw shale.  Heat transfer  from the
 ceramic  balls  raises  the  shale  temperature   to  approximately  900°F, and
 pyrolysis,  or retorting, of the kerogen  in the  shale occurs,  the pyrolysis
 vapors  and  the mixture of balls  and pyrolyzed  shale  are then ; taken to  an
 accumulator vessel.   This  accumulator  consists  of a  rotating,   perforated
 screen or trommel  which retains the  balls  but allows the pulverized  shale  to
 pass through,  thus affording a separation  of the two.    The pyrolysis vapors
 are removed from  the vapor dome at  the  top  of  the  accumulator and sent  to a
 fractionator for oil recovery, while  the  ceramic balls are sent for recycling
 and the processed  shale is eventually sent  for disposal.

     In  the  oil  recovery  section,   the  pyrolysis  vapors  are  separated  by
 fractionation into gas,  naphtha oil,  gas  oil, bottom oil, and  gas condensate,
 or  foul  water.   Each  stream  is sent to  its respective processing unit for
 appropriate treatment.

     Since  some processed  shale  dust is  contained  with  the ceramic  balls  as
 they emerge from  the  accumulator,  the balls have  to be cleaned before  they
 can be  recycled.   Dusty balls  are drppped  into a ball-cleaner vessel where
 they are  blasted  by  hot flue  gas  from the steam superheater.  The  airborne
 particulate matter is  subsequently converted to  a  sludge in  the venturi wet
 scrubber  and  sent to the disposal  area,  and the cleaned flue gas is emitted
 to  the  atmosphere through  the  scrubber  stack.  The  clean ceramic balls are
 then transported  by  a  bucket elevator  to  the  ball  heater  for'heating and
 recycling back to the retort.

     The hot processed  shale from the accumulator is taken to  a rotating drum
 steatm generator/cooler  where  it is   cooled  to  about 300°F by indirect  heat
 transfer  to the  feedwater,  whereby  some  process  steam  is  generated.   The
 cooled processed  shale  is  then taken to  another rotating drum and processed
 shale moisturizing water is added.   Steam  incidentally produced  during the
moisturizing operation  entrains some processed shale dust which is removed  in
the venturi  wet scrubber;  the  steam, along with a little particulate'matter,
 is  released to  the atmosphere  through  the scrubber stack.    The processed
 shale,  cooled  to  below 200°F,  is  moisturized to  approximately  14% water by


                                     36

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weight- (to  aid compaction  and  dust  control)  and then  transported to  the
disposal  area.

      In   the  ball  heater,  treated fuel  gas  and  shale  oil  are  burned  by
atomizing the fuels with  air  in  a vertical combustion chamber  at the top of
the  vessel.   Hot flue gas thus  generated passes downward, concurrently with
the  balls, thereby  heating them. „ The  flue  gas  is separated from the  balls in
the  gas disengagers and  the  hot balls  are-returned  to  the  retort.

      The  disengaged  hot  flue  gas  is used  to preheat the  raw shale feed,
thereby most of the waste heat is  recovered.   The  preheating  system  consists
of  a  series of  three  lift pipes  (or   preheat  zones),   a  thermal   oxidizer
(incinerator),  cyclones  and  wet scrubbers.  The flue gas is introduced at  the
bottom of the last  lift  pipe (first preheat zone),  where the raw shale stream
from the  second lift pipe  (second  preheat zone) is  also received.  The solids
are  lifted  pneumatically and heat  transfer from the gas to the  shale occurs.
The  preheated shale is accumulated  in  a collecting  bin at  the  top of  the lift
pipe and  sent to the retort.  Residual dust in  the  flue gas is separated by a
cyclone and  added to the feed to the retort.

      Since the  flue gas  temperature is at  its  highest when introduced to  the
last lift pipe (first  preheat  zone),  it partially  retorts the  very fine
shale,  which   results   in   hydrocarbon   vapor  release  into   the flue  gas.
Therefore, the  flue gas  is  introduced to a thermal oxidizer (located between
the  first and  second preheat zones)  to burn  the  hydrocarbons  so  that  the
hydrocarbon  emission to  the  atmosphere is not too excessive.   Some shale oil,
C4  liquids,  and air  are  also added to  the  oxidizer  to  sustain combustion.
The  resulting flue gas  is  cooled,  by heat  recovery  in  raising some steam,
then  introduced to the  bottom of the  other two lift  pipes.   At this point,
the  temperature of the flue  gas is  low enough so that the extent of retorting
of  the fine shale  is   less  than  in  the  first preheat  zone.  Hydrocarbons
released  in   these  two  lift pipes  are   emitted with  the flue  gas,  without
incineration.

     All  lift pipes  operate  in a  similar fashion,  i.e.,  the  accumulated  raw
shale from a previous lift pipe is introduced  to the bottom of the next lift
pipe and the flue gas flows  in an opposite  direction.   Finally, after heating
the  raw shale in the first  lift  pipe  (third preheat zone), the flue gas is
wet-scrubbed  for dust  removal  in a  high  energy venturi  scrubber and emitted
to the  atmosphere.   The  raw shale  feed  to the first  lift pipe is   received
from the  surge hopper.

     The  pyrolysis  system  also includes  a  shale oil-fired steam1 superheater
which sends  superheated  steam  to various units  in  the system.  The  function
of this steam  is to provide seals  for rotating and moving parts, as well as
to provide  dew point control for  the  retort vapors.   The flue  gas  from the
superheater,  as mentioned earlier,  is  used  in dedusting of the ceramic balls.

2.2  POLLUTION CONTROL CASE STUDIES                      .

     Three different  pollution control  case studies  have been  examined  in
detail.   Two  of these  cases  depict different technologies  for air pollution

                                     38

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 control (retort gas treatment), while the remaining case considers additional
 cleanup of  the  process  water.   These changes  in the  otherwise integrated
 plant  have  only  a minor  impact on  solid  waste disposal;  thus,  only  one
 approach,  based  on  Colony's  CMLRB  permit  for  solid  waste  disposal,   is
 provided.    Although  these  specific  cases  are  discussed  throughout  this
 manual, they are  intended  to serve  as illustrative examples  only and should
 not limit  consideration of other alternatives.
                                             •                    i    •   .      •
      Since  standard  industry  practices   are   adopted  for  various  minor
 treatments (e.g.,  boiler  feedwater makeup treatment),  these are not discussed
 in detail.  The impact on  the cost  of treatment as a  result of- variations in
 the pollution control strategy  in other  processing areas  is  assessed,-  but a
 detailed analysis  of the  treatment technology itself is  not presented.

 2.2,1  Key Features of  Pollution Control

      One  unique  feature  of  this  manual  that  is  not  included  in other  oil
 shale PCTMs  is the  inclusion  of product  upgrading.  A portion  of the retort
 gas (C3 hydrocarbons) is upgraded to  produce a salable  product (LPG), while
 the shale oil   (net  amount  after in-plant  use)  is upgraded  to   reduce  its
 nitrogen and sulfur content,  viscosity, and  pour point so that the oil  can be
 processed  in conventional refineries  to yield more  useful  products.   Because
 of these specified end  uses for the  upgraded products, the  cleanup of the  raw
 materials  is considered a part  of the process rather than  pollution  control.
 However, there  are certain caveats which  should  be emphasized.

      The C3   and  C4 hydrocarbons  in  the   retort gas are  separated from  the
 remaining  gaseous  components  as  a  single stream  (see Section 3  for a  detailed
 process  description), subjected  to removal of H2S,  and then  fractionated into
 LPG  and C4  liquids.   The latter  is consumed as  plant  fuel; therefore,  the
 removal  of  H2S  from  C4 hydrocarbons  is  essentially  a  pollution  control
 measure.   On the  other hand,  the LPG product  is for  sale;  therefore,   the
 removal  of H2S  from C3  hydrocarbons  could  be  considered  as a part of  the
 process.   Thus,  a  portion  of the cost of C3/C4 hydrocarbons  cleanup may  be
 attributed to pollution control and the remainder to the process.   If the  C3
 and  C4  hydrocarbons  had been  fractionated   before  the  removal of H2S,   the
 distinction  between pollution  control  and  process  cost components would  be
 clearer.

      In  the   process of  removing H2S  from  a   gaseous  feed,  either as a
 pollution  control  measure  or  as  an . integral  part  of  the  process,   an
 H2S-containing  waste stream  will be  produced  and its  treatment would   be
 considered pollution control.

     In  the   case,  of  oil  upgrading,  hydrotreatment  produces ammonia  and
 hydrogen sulfide as a result  of reduction of organically bound nitrogen and
 sulfur.  These  species  are- removed  as wastes from  the  upgraded product and
 eventually recovered as anhydrous ammonia and elemental  sulfur, respectively.
Clearly, producing  the  wastes (by hydrotreatment) is not a pollution control
measure, but treating  them  in  order  to   reduce the potential  of pollutant
 release into  the environment is a control  measure.
                                     39

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      By  virtue  of  indirect  retorting,  the  TOSCO  II  process  produces  a
 carbonaceous processed  shale  which is  disposed of  in  a  surface  landfill.
 This  landfill  was  designed by  Colony  in  accordance with/the  requirements
 imposed in the  CMLRB solid waste disposal permit.

      Underground room-and-piliar mining will be a sizable undertaking.   While
 most  of   the  materials  handling  and  transportation operations  will  have
 controls  for dust emissions, the mine ventilation system will  not employ any
 particulate controls.   Instead, an adequate quantity of air from outside will
 be circulated  in the mine to provide fresh air and also to clear.blast fumes,
 diesel exhaust  fumes,  and dust  so that applicable standards or  guidelines are
 not violated.

 2.2.2  Pollution Control  Case Studies

      The  block  flow  diagrams for the three case studies (A, B and  C)  examined
 in this  manual  are  presented  in Figures 2.2-1 and  2.2-2.  Major pollution
 control  activities  are  indicated by  the heavy-lined  boxes  in the  figures.
 Case  Study A  is the  base  plant as  presented in the Colony EIS  (U.S.  DOI,
 1977) and in Colony's  PSD  permit application  (Colony  Development Operation,
 1977).  Case Study B is  identical  to A  in the  areas  of air  pollution  control,
 solid waste disposal, and  primary  foul  water treatment.   In addition,  it
 examines  a  secondary treatment  (biological  oxidation)  for the  foul,  water
 cleanup,  as presented in Colony's  EIA (Colony Development Operation,  1974).
 Case Study C analyzes an alternate  technology (Stretford)  for  the retort gas
 cleanup,  as  proposed by several  oil  shale developers  and included as part of.
 the  retort  gas  cleanup  system  in Colony's  EIA;  otherwise,  Case  Study C
 remains similar  to A.

      Case Stjudy  A:   Proposed by Colony—

      The  basic  processing  and  pollution  control  systems proposed by  Colony
 are presented  in  this   case  study.   A  process  flow diagram is shown  in
 Figure 2.2-1, and a  brief overview of the  entire process  follows.

      Mined  and  crushed shale is preheated with the hot  flue gases from  the
 ball  heater and  then pyrolyzed  using hot ceramic balls.   The  pyrolysis  vapors
 are fractionated into retort gas,  naphtha,  gas oil,  bottoms  oil,  and  foul
water,  all  of which are treated or  upgraded  before final disposition.   The
 processed  shale  is  separated  from  the  balls  and  then sent  for disposal.
 Fuels  are burned during  the course  of the process,  thereby creating  stack
 emissions.   Also,  materials  handling  generates particulate  emissions  at
 several points in the process.

      Particulate  control   in  the  pyrolysis  system  is  achieved  by   wet
scrubbing, while in other operations it is achieved with  baghouses.  Fugitive
dusts  are  controlled  with  water  and  foam  sprays.   All  of  these   are
conventional industry practices.  The mine ventilation system does not  employ
any control.

     Catalytic  converters on diesel-powered equipment reduce carbon monoxide
emissions.  Hydrocarbons are also controlled to some extent .by these devices.

                                     40

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                                      •5
                                      I
42

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      The retort gas is  further  fractionated into C2 (and  lighter)  and C3/C4
 hydrocarbon  fractions.   Hydrogen sulfide  contained  in  the  retort gas is also
 distributed  between the two  fractions.   Each of these  streams is treated for
 acid  gas  removal  by absorption  in  diethanolamine (DEA); two  individual  DEA
 absorbers  with a  common regenerator are  used to keep the  streams  separate.
 The  acid gas-free C2 and  lighter gas  is  then used as plant fuel  and in steam
 reforming.   The C3/C4 fraction  is further divided into LPG (C3)  for sale and
 C4 liquids for in-plant  consumption.                         ,

      The DEA  regenerator  overhead  gas (acid  gas) is  sent  to a  Claus  sulfur
 plant for recovery of elemental  sulfur.   The tail gas  stream from the  Claus,
 containing unrecovered  sulfur compounds,  is  fed to  a Wellman-Lord unit which
 converts most of  the   sulfur  compounds  to  sulfur  dioxide, which  is  then
 recycled bacic to  the 'Claus unit.   Finally, the Wellman-Lord overhead  gas
 containing   some   sulfur  compounds   is   incinerated   and   emitted  to   the
 atmosphere.   Thus,  the  DEA system, Claus  sulfur plant,  and  Wellman-Lord tail
 gas  unit provide  control over sulfur emissions  by removing  sulfur containing
 species  from  the retort  gas.

      The naphtha  and  gas  oil   are  hydrotreated with hydrogen  from  steam
 reforming.   Nitrogen and  sulfur in  these oils  are reduced  to1 ammonia  and
 hydrogen sulfide which  are  then removed  by  washing  with  water  and in  the
 overhead vapors.   The  wash or sour water  is  subjected  to recovery of ammonia
 as an anhydrous product  by an ammonia recovery process  (e.g.,  Phosam-W).   The
 hydrogen sulfide  containing  overhead  gas  from  the  ammonia recovery unit  is
 sent  to  the  Claus unit  for recovery of sulfur.   The stripped sour water  from
 the ammonia  recovery unit is recycled back to the hydrotreaters  for  reuse  as
wash  water.    In   this   manner,   the  ammonia  recovery  process  provides  an
 indirect control over nitrogen oxides emission by recovering  ammonia  from the
 fuels prior to their combustion.

      The  foul  water,   or  gas   condensate,   containing  dissolved   ammonia,
hydrogen sulfide,  and  organics,  is  steam  stripped to remove  these compounds.
The   stripped  water,  still  containing   significant  amounts  of  dissolved
organics,  is   used in processed  shale moisturizing.   The stripper overheads
are  directed  to   the  Claus  unit  which  converts  the  hydrogen  sulfide  to
elemental  sulfur and the ammonia to elemental nitrogen.  By  removing ammonia
and   hydrogen  sulfide  from   the foul  water,  the  steam  stripper   aids  in
controlling the pollution from these species.

     The bottoms oil  (or residuum)  from the  pyrolysis  fractionator  is coked
to produce ,gas, naphtha, gas oil and coke.  The  first three  streams are  sent
to their respective treatment and upgrading units, while the coke  is disposed
of with  the   processed  shale.   The coke  can be  sold if  a  commercial market
exists for  it; however, this is  unlikely  because the coke  will  have a  high
ash content  due to  the  accumulation  of particulates and asphaltines in the
bottoms oil.   Steam used for cutting the coked material  condenses overhead  to
produce  a small   amount of  foul water  which   is  sent to  the  foul  water
stripper,                              :

     The processed shale and  other  plant wastes are  disposed of in a surface
landfill  based on  a design which has  been permitted by the CMLRB.


                                     43

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      Proper maintenance of  valves,  pumps, etc., and suitable product storage
 tanks provide control over fugitive hydrocarbon emissions.

      Conventional  water  management practices  (source water  clarification,
 boiler feedwater softening, cooling water treatment,  etc.)  produce sludges
 and brines which are disposed of with the processed shale.               .

      Case Study B:   Foul Water; Biological Oxidation—

      This case  study examines  cleanup  of the  steam-stripped  foul  water  by
 biological  oxidation.   It  is  identical  to  the base case  study (A)  in  all
 other  aspects.   A  block  flow  diagram  for  this case  study is  included  in
 Figure 2.2-1.

      The   foul  water contains  a  substantial   amount  of dissolved  organic
 matter. Approximately 80% of this  amount is assumed to  remain  in  the water
'after  steam  stripping.   While  it  is possible  that the  steam-stripped  foul
 water might be suitable  for processed shale moisturizing,  it is also possible
 that some  additional control  of  orgahics may be necessary  to  meet specific
 requirements.   A biological  oxidation system  is  used in this  case study  to
 control the biologically degradable material  in the stripped foul water.   The
 bio-treated water is then  used in processed shale moisturizing.

      Case Study C:   Retort Gas; Stretford Sulfur Recovery—

      This case  study is  the same  as  the pollution  control  system  in  Case
 Study A,  except that the Stretford sulfur process is used  instead of the DEA,
 Clams and Wellman-Lord  processes.   The  use of DEA and Stretford was proposed
 by Colony  in  its  EIA  (Colony Development Operation,  1974).  The  Stretford
 process is a technology that has been historically favored  by  the oil shale.
 developers.   A flow diagram for this case study is presented in Ftgure 2.2-2.
 The design  was  provided  by  a commercial  vendor  and is  based  on technology
 currently in use in the  petroleum industry.

      Two  separate  Stretford absorbers-^one  for the C2 and  lighter fraction
 and the other for  the C3/C4 fraction—with a common  regenerator, are used  to
 convert the hydrogen sulfide in the retort gas  into elemental  sulfur.   Unlike
 the DEA system,  the  Stretford  process  removes only a small  amount of carbon
 dioxide from the gas stream;  therefore,  the  treated gases will  contain about
 94% of the original  amount  of carbon dioxide,  thereby decreasing the heating.
 value.                                                            ;

      The  Stretford  process  will  also generate an  additional   stream:  the
 oxidizer  vent gas.   A  large amount of air  is  used to regenerate  or  oxidize
 the Stretford solution.    This  stripping  air  is then used in the, ball  heater
 as a supplemental  source  of combustion  air,  thus it  is not  emitted directly
 to the atmosphere.    Also, adsorption  on  the  fine raw  shale  in  the lift pipes
 and scrubbing  in  high  energy  wet scrubbers  would  reduce  the emission  of
 sulfur dioxide  resulting from the oxidizer vent gas.
                                      44

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2.3  SUMMARY OF POLLUTION CONTROL TECHNOLOGIES AND COST

     The  control  technologies examined in the case studies are summarized  in
Table 2.3-1.  As  a means of organizing the presentation, the plant complex  is
divided  into  different areas of processing activities and pollution control.
It  should foe noted  that the control technologies examined  here  are not the
only  choices available  nor  are they  necessarily sufficient  for pollution
control;  rather, .they  are merely examples from broad classes of technologies.
These examples  have  been examined on the basis  that  they have been proposed
at  one  time or  another by oil  shale developers.   Additionally,  good vendor
guarantees  and  cost  data  on  these  technologies were  available  for  the
economic  analysis.                                            '  !   .'

     Throughout   this  analysis  of  the  TOSCO II project,  the  distinction
between  process  and  pollution control  is not always clear.  For example, the
diethanolamine  treatment  of  the  C3  hydrocarbons  could  be  considered  a
pollution control  measure  because it affords removal  of H2S.  However, since
the main  purpose  behind the treatment is to  sell the gas as LPG  and  not  to
use  it  on  site, the  treatment  could  be  considered a  processing  step.
Similarly, boiler feedwater treatment, cooling tower makeup treatment,  source
water  clarification,  etc.,  are listed  as  pollution  control measures,  when
they  may also  be classified  as process related activities.   In  some  such
instances—for  example,  the  cooling tower  makeup treatment—only  the  cost
increase  due  to  the  pollution  control activities  is  included, but  this
distinction  is  not  always   possible.   Consideration  of  an  activity  as  a
pollution control  or  as  a  process  related  activity  becomes  important  when
calculating  the  total  cost  of  pollution  control.    Because  all  of  the
borderline activities  are  classified as  pollution control,  the user  of this
manual  should  be made  aware  that  the  total  pollution  control  costs  are
conservatively stated  due  to  the inclusion of activities which could also  be
considered process related.

     Table 2.3-2  lists the control technologies examined in the case studies,
along with  information describing location, control function and  size.   The
case Study  in which  each control is shown  is  also indicated.   More detailed
design  information  for  the  technologies   is  presented  in  Section 5.   A
discussion of other  possible  control choices is  also given  in  that section.

     Table 2.3-3  summarizes  the  costs  of  air  pollution  control,   water
management  and  pollution control, and  solid waste management for the three
case studies analyzed  for  the TOSCO II facility.  Detailed engineering costs
for  the  technologies  analyzed  and  the cost  computation  methodology  are
presented in Section 6.

     In  the  area  of  air  pollution  control,   Case   Studies A   and  B  are
identical,  with  both  including  the  DEA/Claus/Wellman-Lord  technologies  for
the control  of sulfur.   In Case Study C,  the Holmes-Stretford sulfur recovery
process  was  analyzed  as the  control.   The  Stretford  process has  somewhat
lower fixed capital  and direct  annual  operating costs than  those for  the
DEA/Claus/Wellman-Lord system;  this  is  reflected in  the  lower total  annual
operating cost, total  annual  control cost,  and per-barrel control  costs for
Case Study C.


                                     45

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     In  the  area of  water management and  pollution  control,  Case Studies A
and C are- essentially the same, except that the ammonia recovery unit in Case
Study C  is  slightly  larger  than  the  one  used  in  Case Study A  due  to
processing of  the  foul  water  stripper  overhead  vapors.   As  a  result,  the
fixed capital  cost for  Case Study C  is  higher;,  however,  this  is more than
offset by  a  larger  by-product credit from the recovered  ammonia.   In Case
Study B,  biological oxidation  of  the stripped  foul water  was  analyzed as an
additional wastewater treatment, causing the overall water treatment costs to
be higher than those for Case Study A or B.

     The  costs  for solid  waste management are identical   in  all  three case
studies.
                                     51

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                                  SECTION 3                      ;

                    PROCESS FLOW DIAGRAMS AND FLOW  RATES


     Flow  diagrams  illustrating all operations  in  the TOSCO  II  plant complex
are  presented  in this section.  The  integrated  designs  shown are consistent
with the development plans proposed by Colony.

3.1  STRUCTURE OFTHE DIAGRAMS

     In order to understand the interactions throughout the plant complex, an
overall flow diagram  is presented first, followed  by flow diagrams for each
unit  process.    Flow  rates   for  all  major  process and  waste  streams  are
indicated  on each of the more detailed diagrams; flow rates for  streams of an
auxiliary  nature,  such as  cooling Water and  steam, are  included only when
relevant  to .pollution  control  activities.   The following symbols  are used
to indicate the physical state of each stream:

     •     Gases—Circles

     •     Liquids—Squares

     •     Solids—Hexagons.

     A  unique  stream number  is placed within each symbol.   In addition,  an
asterisk (*)  is  placed  next  to  the symbol  for a  stream if  it  comes into
contact  with  the   environment  at  any  point  in   the  process.  The  stream
numbering  system established  in this section is used throughout this manual.

3.2  OVERALL PLANT COMPLEX

     The flow  diagram of  the complete plant complex,  emphasizing  the waste
streams produced,  is  presented in Figure 3.2-1.   Production-scale  mining of
the  oil  shale  will be  accomplished  by  conventional  underground  room-and-
pillar mining.   Initial excavation will begin from a portal bench constructed
in the  upper section  of  the Middle  Fork Canyon,  at an  elevation  of about
7,000 feet, at which  point the Mahogany oil shale  zone  outcrops on opposite
sides  of   the  canyon.   The  excavated shale will  be primary-crushed  at  the
portal  bench and then conveyed to the plant site on the Roan Plateau, approx-
imately 900 feet  above the  bench,  where  the raw shale will  be fine-crushed
and fed to the  retorts.   The mining, crushing,  and conveying operations will
generate particutate emissions.

     The retorting  will  be accomplished by  mixing  the  raw shale  with  hot
ceramic balls in rotating,  drum-type retorts.   The  pyrolysis  vapors will  be
fractionated into retort  gas,  foul  water,  naphtha  oil, gas  oil, and bottoms


                   •           ,       53

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                                        I
                                        Ss
                                        I2.
                                       • 38
54

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 oil  and  sent for treatment to  different sections of the plant.-  The  ceramic
 balls  are heated by  direct combustion of process  fuels  in the ball  heater.
 This,  along  with  raw shale  preheating,  will  create a  flue  gas emission
 containing  entrained  particulates.   The ball dedusting  and processed shale
 cooling   and  moisturizing  operations  will  also  generate  flue  gas  and
.;particulate,  emissions.  Additionally,  these  operations  produce particulate
 sludges because of  final wet scrubbing of the  flue gas streams.

      In Case Studies A and B, the acid gases  (H2S, C02) in the retort  gas are-
 separated by absorption  in a diethanolamine  solution as a pretreatment step.
 The  treated  sweet  gas is  eventually separated into C4 liquids,  LPG,  and C2
 and  lighter process  gas.   Sulfur from  the  acid  gases  is  recovered  fay  the
 Claus/Wellman-Lord processes.   A tail gas stream containing a small amount of
 sulfur dioxide  is eventually  emitted from the Wellman-Lord  unit.   An acidic
 condensate  is  also  obtained  from the Wellman-Lord  unit;  it  is  neutralized
 with alkali and then sent for disposal.

      In  Case Study C,  the hydrogen  sulfide  in  the  retort gas  is directly
 converted  to  elemental  sulfur  by  the  Stretford  sulfur recovery  process.
 Neither  a , pretreatment  step  nor  a  tail   gas  unit  is  necessary.   Any
 unconverted  sulfur  compounds  are  released  in  the oxidizer  vent  gas which is
 used as  a source of  combustion air  in  the  ball  heater;  thus,  there is no
 direct emission  from  the  Stretford  process.  The spent Stretford  liquor is
 removed periodically and  sent for reclamation.

      The naphtha and  gas oils  are hydrotreated to produce upgraded syncrude.
 An amraoniacal wash  water is produced from  the hydrogenation and subjected to
 an  ammonia   recovery  process.   This  latter  process  produces  a  sulfurous
 overhead which is sent either to the  Claus  plant (Case Studies  A,and B) or to
 the  Stretford  plant  (Case  Study C)  for  recovery  of sulfur.   The  hydro-
 treatment operations  consume  process gas,  thereby  generating  flue  gases.
 The ammonia  plant does not  burn any fuels.

      The  bottoms oil  is coked  to  yield a gaseous  overhead,  naphtha oil,  and
 gas oil which are sent to  their respective units  for treatment,  and a  "green
 coke" residue which is disposed of with  the  processed shale.   A  small  amount
 of aqueous condensate  is also  produced and sent to  the foul water  stripper.
 A  gas^fired  furnace  is used for heating the feed  to the coke  drums.   The flue
 gas from  the  furnace is emitted to  the atmosphere.

      Hydrogen for  the oil  hydrotreating  is  generated by steam  reforming,
 using the  treated  process  gas  (C2  and 'lighter fraction).   The  reforming
 furnaces  burn fuel and generate a  flue emission.   Carbon dioxide,  generated
 as a result  of  reforming, is separated from the hydrogen and  is also released
 to the  atmosphere.

      The  foul water condensed from the pyrolysis  vapors is  steam  stripped to
 remove  volatile  matter which  is   sent  to the Claus plant  for  recovery of
 sulfur.  Ammonia  in  the stripper overheads  is converted to elemental  nitrogen
 during  incineration  in. the Claus process.  The stripped water either is used
 in processed  shale  moisturizing  (Case  Studies A  and C)  or  it  is treated
 further using biological oxidation  (Case  Study B)  to  reduce the biodegradable


                                      55

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 organic matter.   Bio-oxidation  yields  a  cleaner water  which  is  used  in
 processed  shale moisturizing .and a  sludge  for disposal  or possible  use  in
 revegetation  if its  composition  is determined  to be acceptable.

     Water  management activities  in all  case studies produce  cooling tower
 evaporation   and  drift,  boiler  blowdown,   clarifier  sludge,  and   boiler
 feedwater  treatment  concentrate,  all  of which  are  either emitted  to the
 atmosphere or used in processed  shale moisturizing  and thus  come: into contact
 with  the  environment.   Also,  materials handling produces  fugitive  dust,
 product storage generates  hydrocarbon emissions, and diesel-powered equipment
 emit exhaust  gases into  the  atmosphere.          •

     The individual  processing and pollution control activities  that form the
 integrated plant are discussed below. .    . .  .

 3.3  UNIT PROCESS FLOW DIAGRAMS

     This  section  describes the operation of the  TOSCO II  plant complex  in
 more  detail   using   flow  diagrams   for  each unit  process  in  the   plant.
 Figure  3.3-1  is intended  to be  used as  a road map showing the  relationship
 between the  unit process  flow  diagrams for all   case  studies.   Each box
 (except the  product  storage boxes)   in  the  figure  represents  an individual
 flow  diagram,   and   the   appropriate figure   number   for   each   diagram   is
 indicated.   All streams are numbered as  well.  A  complete list of all the
 streams, in numerical  order, is  included  in Section  1.7, Table 1,7-1.'

     The individual,  unit  process flow diagrams are  presented throughout this
 section  (see  Figures 3.3-2 through 3.3-15);  also,  Figures  3.3-16 through
 3.3-18  provide details  on the water management system for  the entire plant
 complex.  In  each  diagram, streams enter on the  left  and exit  on the  right,
 and mass flows  are  given  at the bottom.  Composition data  on  major process
 and waste streams can  be found in Section 4.

 3.3.1  Mining,  Crushing and Transport of Raw Shale

     As  mentioned earlier, the underground mining will be carried out  from a
 mine bench laterally traversing  the   upper portion of  the Middle Fork Canyon.
 The mine bench will  occupy approximately six acres  and will contain a primary
 crusher, mine office, equipment  service station,   etc.   Mine entry will  be
 from eight  30-ft by 30-ft adits on  the canyon walls, five on  the  east and
 three on the  west.   The conventional mining cycle  (e.g., drilling, charging,
 blasting, wetting of the broken rock pile, loading,  hauling, scaling and roof
 bolting) will  yield  approximately 56,000 TPSD  of raw  shale.  The:broken shale
will be  loaded in  60- to 90-ton dump trucks with  the  aid of large front-end
 loaders.  Optimum  room and  pillar  size  is  estimated   to be 60  feet on each
 side.    The underground mine will eventually traverse  over  4,000 acres  under
the Colony West property during the 20-year project life.   Several forced-air
mine ventilation openings  will  provide  fresh  air  in  the mine  and will also
aid in  flushing out  the particulate and diesel emissions  (stream 10).  The
mine ventilation system  will not use any particulate  scrubbers.   Instead,  a
sufficiently large amount  (~4  million ACFM)  of air. will  be  drawn in to keep
the particulates and other gaseous emissions  at an  acceptable level.

                           .56

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                                    J
                                    lis
                                    1
57

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      A flow  diagram  for mining  and crushing  operations  is  illustrated  in
 Figure 3.3-2.   The  run-of-mine  shale from  the dump  trucks  will  be  emptied
 into the  top  of the primary crusher,  which is housed in a structure buried in
 the mine  bench.  The  raw shale  will  be  crushed to minus 8 inches in size and
 discharged onto  the  conveyor  at  the   bottom of  the  crusher.   The  shale
 transfer  and  crushing  operations  within  the  primary  crusher will  produce
 particulates  that will  be  controlled by baghouses and  the treated gas, then
 emitted to the atmosphere (streams  2, 3  and 5).

      Approximately   4,500 feet  of   enclosed  conveyors  will   transport  the
 crushed shale  from the mine bench  to  the  plant  site—900 feet higher  in
 elevation--for fine crushing.  During a  portion of  th.e course, the conveyors
 will  pass  through  a  tunnel  to  minimize  the distance,  pitch,  and angle  of
 inclination of the conveyors.  Transfer  of shale between the  conveyors will
 take place in a  completely  enclosed  fashion, and the  fugitive dusts  will  be
 controlled with  foam sprays.

      Under normal operation, the conveyors  will carry the  raw shale  directly
 to   the  fine  crushers;  however,   a  raw  shale  stockpile  of  approximately
 1,500,000  tons  will be  maintained  on  a  plateau  near  the  plant to  assure
 continuous  feed  to  the  retorts should  mining  or  conveying  be  interrupted.
 The airborne  particulates from the  stacking  and reclaiming  operations  will  be
 controlled  with baghouses and foam  sprays.   Any particulates  not  controlled
 will  be emitted in gaseous  streams 4 and  8.   Surface  runoff  and any  leachate
 (stream 12) will  be collected by  a drainage system and redistributed,  after
 oil/water  separation,  to  the processed  shale pile.   The fine  crushers  will
 consist of multiple crushing, screening,  and conveying  systems,  all enclosed
 in  a single building.    The  raw  shale will be  reduced  to minus one-half inch
 in  size and conveyed  to  the  fine  ore storage  silos.  Particulate matter from
 the final   crushing  and storage operations  will be controlled  by  baghouses,
 and  any   uncontrolled  particulates  will   be  emitted to   the   atmosphere
 (streams 6  and 7).   The dust  collected  from all of the baghouses  (stream  9)
 will  be combined with  the  fine ore and fed to the  retorts.

 3.3,2  TOSCO  II Aboveground  Retorting Process

      A  full-sized .TOSCO  II  pyrolysis unit  consists  of  a  raw shale  preheat
 system*  a  ball  heating  and circulating  system,  a  retorting  system,  and a
 processed  shale cooling and moisturizing  system.   The commercial plant  will
 consist of  six identical pyrolysis units.   Figure 3.3-3 shows  a flow  diagram
-for a  single  TOSCO II  pyrolysis  train  (see Section  2  for  a more detailed
 description of the pyrolysis unit).   Fine  crushed  raw  shale (stream 1)  is fed
 through a  surge hopper to a  series  of  preheat  lift pipes where hot flue gas
 from  the  ball  heater also enters and pneumatically  lifts the  raw shale  to a
 collecting  bin  at the  top.  During lifting,  temperature of the raw shale  is
 raised to about 500°F.    Some hydrocarbons  from the raw shale are .consequently
 volatilized,  and  these are incinerated in a  thermal oxidizer which is a  part
 of  the  preheat system.  Some entrained dust in the  flue gas  is separated  by
 cyclones  and  added to the already settled  raw  shale  in the  collecting  bin.
 Finally,  the  flue   gas   is  wet  scrubbed  to  remove   the  remainder  of the
 particulates  and  emitted to the atmosphere  (stream 18).  The  sludge from wet
 scrubbing (stream 21)  is disposed of with the processed  shale.


                                      58

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      Preheated raw shale  from  the collecting bin is fed to the rotating drum
 retort along with hot  ceramic  balls.   The temperature of the shale is raised
 to approximately  900°F and pyrolysis  of the kerogen  occurs.   The pyrolysis
 vapors and  the  solids mixture are  drawn into  an accumulator .vessel  which
 separates  the processed shale  and the balls by  screening  through a trommel.
 Pyrolysis  vapors  (stream  17)  are withdrawn  from the  top  of  the vessel  and
 sent  to a fractionator for  product recovery.   The ceramic  balls are dedusted
 using flue gas from  the steam  superheater.   The flue gas is then wet scrubbed
 for dust removal and emitted  to the atmosphere (stream 19).   The sludge from
 wet scrubbing (stream 22) is disposed  of with the processed shale.  Dedusted
 balls are  sent  via  a  bucket   elevator  to the  ball  heater where they  are
 reheated  and  recycled  to the  retort.   The ball  heater burns  process  fuels
 (streams 44  or 63, and  113  or  114)  for direct heating of the balls, and thus
 generates  a  hot  flue  gas which,  as mentioned  earlier, is  used !in raw  shale
 preheating.   In  addition,  in  Case  Study C,  the  ball  heater  also  receives
 Stretford  oxidizer  vent  gas   (stream 75)  as  supplemental  combustion  air.
                                                                 I
      Hot processed shale from  the accumulator vessel  is first cooled  by heat
 transfer  to   the  boiler feedwater,  which raises  steam  (stream  26), and then
 moisturized   to  approximately  14%  moisture  content  and  sent for disposal
 (stream 27).-   The  moisturizing  process  creates   more steam,  which   then
 entrains  some  processed shale  dust.   This steam  is  wet  scrubbed for  dust
 removal and  vented to the  atmosphere  (stream 20).   The  processed;shale sludge
 (stream 23)  from the scrubber  is  mixed with  the bulk  of the processed  shale
 for disposal.

    ,  The steam superheater burns  process  fuel  (stream  115) to heat the  steam
 that  is used for  sealing purposes  in the  pyrolysis  unit.

 3.3.3  Oil and Gas Recovery  Unit     '   .  „

      Figure  3.3-4  shows  the   initial  treatment   for   upgrading   the  crude
 pyrolysis vapors.  First, the unit separates the products of  pyrolysis;  then,
 it  fractionates the gaseous products, while  sending  the liquid products to
 appropriate  processing  units for upgrading.

      Pyrolysis  vapors   (stream  17)  from  the  retort  are   introduced  to  a
 fractionator column which divides  the vapors into raw retort  gas (stream 28),
 foul  water  (stream 29),  naphtha  oil  (stream  40),  gas  oil  (stream 41), and
 bottoms  oil   (stream 42)  fractions.   The gas  oil   is  sent  to the  gas oil
 hydrogenation  unit  (see Section 3.3.9),  while the  bottoms oil  is sent for
 delayed coking (see Section  3.3.8).                                      ,  '

     The raw  retort  gas  composite  from  the  pyrolysis, hydrotreating, and
 coking units  is compressed and introduced to a reboiled absorber stripper.  A
mixture  of  naphtha  oil  fractions  from  the  same  units  is ;also  added.
 Compression  of  the retort gas  knocks out  some  moisture (stream 30) which is
mixed  with  the foul  water from  the  pyrolysis  fractionator.   The  C2 and
 lighter  compounds (stream 32)   in the  feed  to  the  reboiled  absorber are
stripped and  removed   from  the top,  while  heavier  compounds  dissolve  in
 naphtha which exits from the bottom.
                                     61

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      Since  the  naphtha  contains  dissolved  gases,  it  would,  need  to  be
 stabilized  before  further  treatment.   This  is  achieved by  introducing the
 naphtha stream to a stabilizer column in which C3/C4 compounds (stream 35) in
 the naphtha are  steam  stripped.   The stabilized naphtha  is  then  sent to the
 naphtha  oil   hydrogenation  unit  (see  Section 3.3.10).    A   portion  of the
 stabilized naphtha is  also  used  in a sponge oil absorber to  remove traces of
 heavier compounds .in  the C2  (and  lighter)  fraction; it  is  then  returned to
 the pyrolysis  fractionator.

      Both C2  (and lighter)  and  C3/C4 streams are treated for sulfur removal
 either by  DEA/Claus/Wellman-Lord  systems (Case  Studies  A and  B) or by the
 Strstford process (Case Study C).

      The  foul  water  from the fractionator (stream 29),  compression condensate
 from the  gas  recovery  (stream 30),  and  a condensate from the  delayed  coker
 (stream 99) are  combined  (stream 31) and  steam stripped to  remove  volatile
 matter (stream 37).   The  stripped  water  (stream 38) is either  used  directly
 in  processed  shale  moisturizing (Case Studies  A and C)  or   treated  further
 (Case Study B) and then used  in  processed shale moisturizing.  The  overhead
 volatile  gases from  the steam  stripper  are  sent  to the Claus sulfur  plant
 (see Section 3.3.4).

 3.3.4  Amine Absorption/Claus  Sulfur Recovery Units  (Case  Studies  A and  B)

      The  amine absorber/Claus  system for retort gas treatment  is shown  in
 Figure  3.3-5.   These technologies control the amount of  hydrogen  sulfide  in
 the  process gases;  thus,  they indirectly  control  the sulfur emissions  from
 burning of the process fuels.   The  amine system removes  H2S from the  gases
 and  the Claus  process,  in  turn, converts  the  H2S  to  elemental  sulfur.

      The  amine system includes two separate absorption columns which are  used
 to  treat  two  gas streams:  the C2  and  lighter  stream from  the  sponge  oil
 absorber  (stream  32)  and  the  C3/C4  stream  from the  raw  naphtha  stabilizer
 (stream 35).   These  gas streams  are scrubbed with a  30  weight percent  DEA
 (diethanolamine)  water solution to  reduce H2S  to 130 ppmv concentration  in
 the  treated gas.  The treated C2 and  lighter  gas  (stream 33)  is  used as plant
 fuel, while the C3/C4 stream (stream  36)  is fractionated into  LPG  (stream 54)
 for  sale  and C4 liquids (stream 55)  for  plant use.  Approximately 50% of the
 COS  is also removed,  but the  DEA solution  does not remove   any  appreciable
 amount  of mercaptans.   The C02 in  the  gas streams  is also reduced to a  low
 level  by  absorption  in the amine  solution.   The rich amine  solution leaving
 the  two absorption columns  is combined  and  regenerated  by steam  stripping,
which  produces a  concentrated acid gas  stream from  the top  of the amine
 regenerator  (stream 56).  This concentrated  acid gas  stream   is sent  to the
Claus  sulfur  recovery  unit  along  with  the   overhead  gas from  the  ammonia
recovery process (stream 128).
                                 1              '       .  .         !
     In the Claus process,  air  is carefully  introduced  into the  Claus  feed
stream  to  combust  approximately  one-third of  the H2S to S02,   raising the gas
stream  temperature to  approximately 1,200°F.   This provides a stoichiometric
amount  of  S02 to  react  with  the  H2S.  Elemental  sulfur   (stream 60)  is
produced by the reaction of H2S with S02  in the feed incineration  furnace and


                                      63   .      •

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in three catalyst  (alumina or cobalt-moly) stages downstream of the furnace.
Intermediate  condensers  after  the  furnace  and each  catalyst bed  recover
elemental  sulfur  and generate  60 psi  steam (from cooling water)  to  be used
elsewhere in the plant.

     The rate at which air is introduced into the CTaus unit is controlled to
maintain a  small  excess  amount of  H2S  in the  gas  stream.   After the third
catalyst,bed, the  hot tail gas  (stream 57),  still  containing a small amount
of  H2S,   is  sent  to   a  Wellman-Lord   tail   gas   treating  process  (see
Section 3.3.6).   The  H2S  is  recovered from the  tail  gas  by the We 11 man-Lord
process, converted to S02, and returned to the Glaus plant.

3.3.5  Stretford Sulfur Process (Case Study G)

     A flow diagram for the Stretford process is shown in Figure 3.3-6.  This
process  affords  simultaneous removal  and  recovery  of  hydrogen sulfide from
the gaseous feeds.

     The Stretford process  includes  two separate absorbers,  one, each for C2
and  lighter gases  (stream 32)  and  C3/C4  gases (stream 35), with a single
solution regeneration and  sulfur recovery  system.   The Stretford  solution
consists   of   a  buffered  solution   of   sodium  carbonates,  anthraquinone
disulforiic  acid (ADA),  and sodium vanadate which, in  effect,  oxidize H2S to
elemental  sulfur.  The  reactants are  regenerated by stripping and oxidizing
with air, then are recycled.

     The gas streams  are introduced into the absorbers through venturi inlets
under the  solution level.   By reacting with vanadate in the presence of ADA,
H2S is  converted to  elemental sulfur which then floats to the surface and is
skimmed off in the oxidizer.   After filtering and melting, the sulfur product
(stream 77)  is  taken   to  storage.    The  treated  C2  and  lighter  gases
(stream 34)  are used as  process  gas, while  C3/C4  gases  (stream  72)  are
fractionated Into LPG and C4 liquids (streams 73 and 74).

     Stripping air is purged through the  Stretford  solution  in the  oxidizer
tank to  regenerate the  ADA.   The oxidizer vent gas, containing, the stripping
air with  some desorbed  materials (stream  75), is then used  as a combustion
air source  for  the ball  heater.  The regenerated solution is recycled to the
absorbers.   Some  nonregenerable compounds like  thiosulfates  form  during the
solution regeneration..  These  are removed  periodically as part of the spent
liquor (stream 76), which is sent for reclaim or disposal.

     The Stretford process selectively  removes  H2S, but it  does  not remove
other sulfur compounds such as COS, RSH and CS2.   Some of these compounds are
partially absorbed in the solution but are desorbed again  during stripping.
Unlike  amine  absorption,  which  also  removes  99% of C02  from the gas,  the
Stretford  process  does  not  appreciably remove  C02; therefore,  the  heating
value of the Stretford treated process gas is considerably lower than that of
the amine treated gas.
                                     65

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 3.3.6  WeTlman-Lord Tall  Gas  Process (Case Studies  A and B)

      A  schematic for the  Wellman-Lord process is presented  in  Figure 3.3-7.
 This  process controls the  sulfur  emissions from  the Glaus  unit  by recovering
 H2S  from  the Glaus  tail gas,  converting it to  S02,  and then  recycling it back
 to the  Glaus unit.
                                                                 i
      The  Glaus tail gas  (stream 57)  is introduced  into an  incinerator  along
 with  process  fuel   (stream  46)   and  combustion  air  (stream  79).    Sulfur
 compounds  in the  feed  streams are  converted  to  S02 upon incineration.   Hot
 combustion  products are cooled, at  first  by waste  heat recovery  and then by
 quenching   with  water.    Any  sulfur   trioxide  produced   during  the   feed
 incineration is condensed  along with the moisture in  the combustion products,
 forming sulfuric acid.   The  acidic  condensate is removed from  the  bottom of
 the   quench  tower,  neutralized with  alkali,  and  then  sent  for  disposal
 (stream 86).

      The  cooled gaseous  stream is  then introduced into the S02  absorption
 tower which circulates  a solution of sodium sulfite,  Na2S03.  The S02  in  the
 gas  is  absorbed in the sulfite solution,  producing  sodium bisulfite,  NaHS03.
 The  resulting  rich solution  is-  removed  from the  bottom  and  sent to  the
 evaporator  for  regeneration.   A clean  tail gas (stream  82),  practically'free
 from  any  S02,  emerges  from  the  top of the  S02  absorber  and is emitted  to
 atmosphere without  further  treatment.

      In the evaporator,  the NaHS03  solution is indirectly heated  with steam,
 whereby  S02  desorbs  and  Na2S03   reforms.   Water  vapors  in  the   evaporator
 overhead  are condensed,  while the gas  containing S02  (stream 83)  is  recycled
 to the  Glaus unit.   The  Na2S03  slurry is withdrawn  from  the bottom.of  the
 evaporator   into  a  dissolving tank.    The  evaporator  overhead'  condensate,
 makeup  chemicals,  and makeup  water  are  also added  to the dissolving tank to
 reconstitute the Na2S03  solution,  which  is then returned  to  the  absorber.

 3.3.7  Hydrogen Unit

      Hydrogen  is  used  in  naphtha  oil and gas  oil  hydrotreaters  for  oil
 upgrading.   The hydrogen  is  produced  from  a  portion of the treated C2  and
 lighter process gas (stream 53  or 71) by using a  conventional steam  reforming
 process,  as  depicted in  Figure 3.3-8.   The catalysts  used  in reforming  are
 vulnerable  to  poisoning  by  sulfur  compounds; therefore,   only the treated
 process gas  is used.

     The  hydrogen  unit consists  of a  hot,  cobalt-molybdenum catalyst  guard
bed  to  convert  most  residual  sulfur  compounds   in  the  process  gas  to H2S,
which is  then  absorbed  in an  amine solution, regenerated  (stream 92), and
 sent  to the  Glaus  (or Stretford) unit.  Any remaining H2S in the process gas
 is removed by passing through a zinc oxide bed.

     The desulfurized gas  is  then mixed with  superheated steam  and reformed
over  a  nickel-based catalyst  at  1,400° to 1,600°F  to  produce  a  mixture of
hydrogen,  carbon  dioxide,  carbon  monoxide and unreacted steam.   The latter
two compounds are  then  reacted over  a  high  temperature, iron-chromium  oxide


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 shift  catalyst and  a low  temperature,  copper-zinc  oxide  shift' catalyst  to
 produce  more hydrogen and  carbon  dioxide.   The carbon dioxide  is  removed by
 absorption  in an  amine  solution  and emitted  to  the atmosphere after amine
 regeneration.   This  emission  (stream 97)  also  contains a  large  amount  of
 steam which  is produced  during the regeneration process.

     Finally, the  hydrogen  overhead from  the  amine absorber  is  passed through
 a  nickel-based  methanator to  convert any residual  carbon monoxrcle  and carbon
 dioxide  to  methane by reaction with hydrogen.   The treated  hydrogen product
 is  then  split into a  feed  going  to  the  gas  oil  hydrotreater (stream 95)  and
 another  going to the  naphtha  oil hydrotreater (stream 96).

     The reforming   furnaces   burn  process   gas   (stream 47  or   65)  which
 generates a  flue  gas^ emission  (stream 91)  to the atmosphere.   Several  spent
 catalysts (stream  94) are also produced,  and these are  removed as required.

 3.3.8  Delayed Coker

     The residuum  or bottoms oil  (stream 42) from the pyrolysis fractionator
 has  a  high  boiling  point  (~950°F)  and  contains asphaltene  material.   Since
 this oil has a  low  market  value,  it is upgraded  into  more useful  lighter
 products  by  thermal  cracking.  Figure 3.3-9  presents  a  flow diagram  for  the
 delayed  coker unit.

     The  bottoms  oil  is  heated  and  charged to  the  bottom  of  a  coker
 fractionator   in   which   the  lighter   components   are  flashed   off   and
 fractionated.  The  oil  is further  heated to  cracking  temperatures  and fed ,to
 an  insulated  coke  drum where cracking of the  oil  occurs.   Hot  vapors
 containing gas,  naphtha  oil,  and  gas oil are  produced,  and coke  is  formed.
 The  vapors  are fed  to the  fractionator  where  they are  separated  into  their
 respective  products  (streams 98,   100,   and  101)  and  sent  to appropriate
 upgrading units.
                                                                 •
     Once a  coke  drum is filled,  the feed is diverted to another  coke  drum.
 Steam  stripping  of  the  coke  is   then  carried  out   to   remove   volatile
 components.   The coke i-s cooled by  injecting water, removed  froni the  drum  by
 cutting  with  high   pressure  water  jets,  and   then   sent  for   disposal
 (stream  103).   the  steam  used   for stripping  condenses   overhead   of the
 fractionator and forms  a foul water  (stream  99)  which is separated  from the
 condensed oil and sent to the foul water  stripper.

     The  coker  feed  furnace  combusts  the  process  gas  (streanv 48  or 66),
 resulting in a  flue  gas  (stream 104)  that is  emitted to  the: atmosphere.

3.3,,9  Gas Oil Hydrotreater
                                   :       •           •     ''•'('
     This unit  upgrades  the  crude  gas  oil  fractions,  obtained from the
pyrolysis unit  (stream 41)  and  the  delayed  coker (stream 101), into a low
sulfur,   low  nitrogen  gas  oil.  The  oil  viscosity  and  pour point  are also
decreased  to  facilitate  better  handling.   A  flow  diagram  for  gas oil
hydrogenation is presented in Figure  3.3-10.
                                     70

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      The mixed gas oils.and  hydrogen (stream 95) from  the  hydrogen unit are
 blended together and  heated to reaction temperatures in two parallel reaction
 furnaces.   The preheated blend  is  then passed through a hydrodenitrogenation
 (HDN) catalyst at a  high temperature and pressure.   The oil is hydrogenated,
 and organically bound nitrogen and  sulfur are reduced to ammonia and hydrogen
 sulfide during this reaction.

      The hydrotreated mixture is then  fed to  a high  pressure ^separator to
 which wash  water (stream 131)  is also added.   Any unreacted hydrogen overhead
 from the separator  is  recycled  back to  be  blended with  the fresh  gas  oil
 feed,  while most  of  the  ammonia and  some hydrogen sulfide  dissolve  in  the
 wash water to  form  a sour water (stream 110).   This sour water  is  removed
 from the bottom of the  separator and sent to  the ammonia  plant for recovery
 of  ammonia.   The oil  is  also   removed  from the bottom and  sent to a  low
 pressure separator.

      Dissolved  gases  in  the oil  are  flashed in the low pressure separator  and
 sent to the  gas recovery  unit.   The  oil  is then further  fractionated  into
 overhead gas  (stream  106),  naphtha oil  (stream 107),  diesel  oil (stream 108),
 and hydrotreated  gas  oil  (stream 117).  The overhead  gas and naphtha are  sent
 to  the  gas recovery  unit,  diesel is used as  fuel  for mining  equipment,  and
 the gas oil is blended  with hydrotreated naphtha to  yield  the final  upgraded
 product.

      The reaction feed furnaces  and  fractionator reboiler furnace use  process
 gas  (streams  49 or  67, and 45 or 64, respectively)   as  fuel.   The  flue gases
 (streams 118  and 119)  from  these   furnaces  are emitted to the: atmosphere.

 3.3,. 10   Naphtha Oil Hydrotreater                            .    • 'J

      In  this  -unit,  stabilized  naphtha  oil  from the gas  recovery unit  is
 hydrotreated  to  produce a  low  sulfur,  low  nitrogen naphtha oil which  is
 blended  with  the hydrotreated gas oil  to produce the final  upgraded fuel  oil
 product.   A  flow diagram for   the  naphtha  oil hydrotreater Is- shown  in
 Figure 3.3-11,

     the  operation  of  this  unit is quite similar   to  that of ithe  gas  oil
 hydrogenation  unit.   Stabilized  naphtha  (stream 40) from  the gas recovery
 unit  is mixed with the  hydrogen (stream 96)  feed from steam reforming  and
 heated to reaction temperature.  The preheated mixture is then  passed through
 a bed  of HDN  catalyst at an elevated temperature and pressure.  During this
 reaction,  the  unsaturated hydrocarbons   in  the oil  are  hydrogenated,   and
essentially  all .of  the  organic nitrogen and  sulfur  are  reduced  to form
ammonia and hydrogen sulfide,                                     ;

     The  excess hydrogen  is   flashed off  in a low pressure  separator  and
recycled to the  front of the  unit;  at the  same  time, wash water (stream 132)
is  added  to absorb  ammonia and hydrogen  sulfide.  The sour water thus  formed
(stream 124)  is  removed  from  the bottom  and  sent to  the  ammonia  plant  for
recovery of ammonia.
                                     73

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     The  washed  naphtha  from  the separator  is  introduced  to  an absorber
vessel  in  which more gases are  flashed  off (stream 121).   A small stream of
hydrotreated  gas oil is  added  through the top of  the  absorber to scrub out
heavier  components  in  the  gas.   The  hydrotreated  naphtha  exits  from the
bottom  of  the absorber and is  blended with the bulk of hydrotreated gas oil
to form the upgraded syncrude product.                           j •

     The   naphtha  feed   reaction  furnace  is  fueled  by  the   process  gas
(stream 50 or 68),  resulting  in a flue  gas  (stream 125)  that is released to
the atmosphere.   Spent  catalysts (stream 122) are  also removed periodically.

3.3.11  Ammonia Recovery  Process

     A schematic flow diagram for an ammonia recovery process is  presented in
Figure 3.3-12.   This  unit treats combined ammoniacal sour water;(streams 110
and 124) from the  two hydrotreating units for recovery of anhydrous ammonia.
In addition,  in Case Study C,  it  receives  the  foul water stripper overheads
(stream 37).

     The ammonia recovery process illustrated consists of  a  water stripper,
an  ammonia absorber,  an  ammonia stripper,  and  an  ammonia  concentrator or
boiler.  The  sour water feed is introduced to the water stripper  in which the
dissolved  ammonia  and other  volatile matter are  evolved  by  steam stripping
the sour water.   The stripped water (streams 131 and 132), for th'e most part,
is returned back to the hydrotreaters as wash water.  A small  purge stream of
the  stripped  water  is used  in  processed shale  moisturizing  (stream 133).

     In the  ammonia absorber,  the released ammoniacal gases and foul  water
stripper  overhead  (stream 37)  are  absorbed out   of  the  vapor  phase  in  a
phosphoric  acid  solution.   $  solution  stoichiometry between  .monoammonium
phosphate  and diammonium  phosphate is maintained for efficient absorption of
ammonia.   Unabsorbed  gases such  as  H2S  and C02 continue on, as the ammonia
recovery unit overhead  vapors  (stream 128), to the Claus (or Stretford) unit
for recovery of sulfur.

   ,  Desorption  of the  ammonia from  the  ammonium phosphate solution  takes
place  in  the  ammonia  stripper  section.    Both  temperature and  'pressure are
raised  and steam  is passed  through  the  solution.   An aqueous  solution of
10-20% ammonia  is  condensed overhead, while the stripped or lean solution is
recycled to the absorption section.  Ammonia is then obtained in an anhydrous
state (stream 129) in the distillation section by steam stripping the aqueous
ammonia solution and fractionating the vapors.  Sodium hydroxide may be added
to the aqueous charge to facilitate release of dissolved ammonia-.

3.3.12  Biological Oxidation (Case Study B)

     Additional  treatment of  the  foul  water after  initial  steam stripping is
provided to  reduce the  residual  organic content of  the  process wastewater.
In general, stripped  oil  shale  wastewaters will  retain much of the foul odor
resulting  from  anaerobic  decomposition of the organics, and oxidation of the
odor  contributing  compounds  serves  to  negate  the problem.  : A  properly
designed   biological   oxidation  system   can   remove  up  to   90%  of  the


                                     75

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 biodegradable   matter   in  wastewaters.   The  high  purity,   oxygen-activated
 sludge   system  was  selected  for  the  oxidation,  and  it  is  presented  in
 Figure  3.3-13.

     Activated  sludge,  nutrients,  and  stripped foul  water (stream 38)  are
 added  to the  bio-reactor,  and  pure  oxygen from  the oxygen, plant is  purged
 through the mixture.   After  a  sufficient, residence  time, the  mixture  is
 clarified  and   filtered  to  produce both a  treated  water (stream 136)  low  in
 organic carbon and  a  sludge (stream  137).  The  water is used for processed
 shale dust  control,  while the  digested  sludge  is used in revegetation  of the
 processed shale disposal site.                                   ;

 3.3.13   Solid Waste  Management                                   !

     A   conceptual   drawing  for   solid, waste  disposal   is  presented   in
 Figure  3.3-14.   Davis  Gulch,  which is a side  drainage of the Middle Fork  of
 Parachute Creek in  the northwestern portion of the Colony property, has  been
 selected by Colony  as  the  disposal   site.  Approximately  900  acres  in the
 gulch will  be  covered with over  400  million  tons of waste material  at the
 completion  of   the project  (20 years).  The solid  waste disposal technology
 described below is  based on Colony's  disposal   permit  from the Colorado Mined
 Land  Reclamation  Board.  Colony has   proposed  to keep  the  hazardous wastes
 segregated  from the  nonhazardous wastes, but detailed plans for the disposal
 of  hazardous  wastes  are   not  presented  in  the  permit application.   The
 following  discussion  applies  to the  disposal  of  nonhazardous  wastes  only.

     The processed shale and other nonhazardous  wastes  will  be 'Combined and
 moisturized at  the plant and then  conveyed to  the Davis Gulch disposal area.
 At the  disposal area,  the waste  material will  be loaded into 150-ton trucks
 and hauled to the active portion of the area.

     The  construction  of  the   landfill  will   take place  in  three  stages,
 beginning  in  the portion  of the  gulch  nearest  to  the processing facility.
 This initial stage will last for approximately  7 1/3 years, during which time
 about .132  million tons  of the waste  material will  be deposited.   In the
 middle  stage,  the waste disposal will take  place in  the farthest portion of
 the gulch,  and  approximately 183 million tons of the wastes will be deposited
 over a  period  of  9 years.   In  the  final stage, about 90 million tons of the
wastes  will  be deposited to  bridge the fills   from the  previous two stages.

     The  waste  material   will  be  placed  in  lifts  of  6-18 inches  for
 compaction.   The  bottom  two feet of the wastes will  be supercompacted to an
 in-place density  in  excess  of 95 lb/ft3 to  form  a  liner which would isolate
the wastes  from  the groundwater and  spring seepage.   The  bulk  of  the fill
will  be compacted to a density of 85 lb/ft3, except for the front and top two
 feet which  will  also  be  supercompacted to provide  a  cover to  reduce the
 infiltration of runoff.

     The  face   of the landfill  will   be   constructed  in  a  multiple-bench
arrangement,  with  a  segmented  slope  of  no  less  than  3H:1V  (3  units
horizontal:  1   unit  vertical)  and  an  overall   slope  of 4H:1V.   After  every
45 feet  in elevation,  15-foot wide benches will  be constructed  to allow for


                                     77

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the  passage  of the disposal and compaction equipment.  The  benches will  have
a back slope of 10:1 to permit the collection of  runoff.

     After  reaching  a  desired  elevation,  the  landfill  surface  will   be
scarified  and  covered with 18 inches of  previously stripped and  stockpiled
soil and subsoil.  The surface will then be mulched,  seeded,  and  irrigated  as
necessary  to  assure  that  the  plant  growth  is reestablished.   The final
contouring of  the landfill will include hills,  valleys,  and swells  to blend
irito the surrounding terrain.

     An  embankment and collection  pond will  be constructed downstream from
the  landfill to  collect the water from the Davis Gulch watershed.  The water
will  include  runoff from  the  landfill  as  well as  runon  from the area above
the  landfill.   The  runoff  will  be  collected from  the  individual  landfill
benches  using  half-round  pipes (1.5-foot diameter)  installed at  the  junction
of  a bench and  the landfill  segment above  it.   The pipes  will empty into
lined ditches which route  the water to the catchment  pond.   The runon will  be
collected  above  the landfill  in unlined ditches which merge with the lined
runoff collection ditches.  The water collected in the catchme.nt  pond will  be
used for processed shale moisturizing.

     In  addition  to the  water collected in the  catchment pond '(streams 12,
150,  177,  178)  many  other waters,  such  as  boiler  blowdown  (stream 168),
cooling  tower  blowdown   (stream 175   or 176)  and   stripped  foul  water
(stream 38), are  also  used for processed shale moisturizing.  Figures 3.3-15
through  3.3-18   (discussed  in  Section 3.3-14)  give  the  makeup  of  the
moisturizing water for" the different case studies.               ;

     Transport of  the  wastes to the disposal  area  and subsequent compaction
activities  generate  fugitive  particulate  emissions  (stream 139).    These
emissions  are  controlled  with  dust  suppression  water  (stream 149).   The
transportation and  compaction vehicles create  diesel emissions  (stream 138)
which.are controlled by catalytic converters.                          .

3.3.14  Water Management

     Water management  for all  case  studies  is presented  in Figure 3.3-15.
Water management  for the  entire plant includes  source water clarification,
boiler  and  cooling   tower  feedwater  treatments,  steam  generation,  and
distribution of  water  to wherever  it  is  needed.   Water needs  and  minimum
quality  requirements   are  closely   associated  to  make   the  management
economically effective and efficient.                             :

     Source  water  (stream 140)  from  the  Colorado   River  is  clarified  and
supplied to different  processing and  utility needs.  A portion of the water
is  softened  in   a  conventional  zeolite  system  and  then   used as  boiler
feedwater  makeup.   The  concentrate   (stream 169)  from the  boiler feedwater
treatment,  as well  as  the blowdown from the  boilers (stream 168), is placed
in an equalization basin and eventually used in processed shale moisturizing.
      . •    '       .      '                                '         !
     The cooling   tower  feedwater  treatment  consists  of  the < addition  of
sulfuric acid  to  prevent  calcium carbonate scaling.   Cooling tower blowdown

                                     80

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(stream 175  or 176)  is  placed  in  the  equalization  basin, while  the drift
(stream 170  or 171)  and evaporation  (stream 173 or 174)  are  emitted to the
atmosphere.

     High  quality water  needs  (e.g.,  for  revegetation,   fire 'and service,
sanitary and potable uses)  are fulfilled by the clarified source water.  The
equalization basin  serves  to  provide low quality  needs,   such  as  processed
shale moisturizing.

     Figures 3.3-16 through 3.3-18 present overall water distribution schemes
for the three case studies.
                                     82

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                                 COLORADO RIVER
FLOWS IN GPM

    113-1
                                                                        EVAPORATION
                                                                        DRIFT
                                                                        LOSSES
  SOURCE • WPA
       FIGURE 3.3-16  OVERALL WATER MANAGEMENT SCHEME, CASE STUDY A

-------
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                                      84

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                                   COLORADO RIVER
     DIGESTED SLUDGE
                  PROCESSED
                    SHALE
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       FIGURE 3.3-18  OVERALL WATER MANAGEMENT SCHEME, CASE STUDY i

                                         85                                ;

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                                  SECTION 4

        INVENTORY AND COMPOSITION OF PLANT PROCESS AND WASTE STREAMS


     The stream  compositions  presented in this section  were  derived, to the
extent  possible,  from pilot  plant test  data.   In the  absence  of data from
actual  source  testing, engineering  analyses (by  Denver Research Institute,
Stone and  Webster  Engineering Corporation and Water Purification Associates)
were  performed  on the  technology and  raw  stream information  from proposed
industrial  developments.   The sources  of these  data,  whether actual, esti-
mated,  or  derived from published or unpublished  information,  are indicated.

     The  data  presented   are internally  consistent  for  the overall  plant
complex; i.e.,  the  principal  chemical  elements involved in emissions, efflu-
ents, and wastes are balanced throughout the plant.  Trace elements generally
are  not considered  because  of the  lack of  consistent  data available  as  a
starting  point.   The  stream  compositions  derived  by  engineering  analysis
generally  agree  with the  available data  from published sources.   Therefore,
the data presented in this section, even though partly derived by engineering
analysis,  are believed to be both representative of the actual operations of
such a  plant  and accurate enough to lead to relevant conclusions in analyses
of various pollution controls.

4.1  INVENTORY OF STREAMS
                                                                 i
     All but the  most minor streams in  the  plant complex are inventoried in
this; section, and  quantitative  data are presented to define  important char-
acteristics of  the  streams.   Section  4.2 presents detailed  compositions of
the major  streams and  shows  changes  in  composition,  from one  point to the
next, throughout the plant.

     The streams  encountered  during the analysis  of pollution  control tech-
nologies for the plant are listed, along with their flow rates and components
of  concern,  in  Tables 4.1-1 (gases),  4.1-3  (liquids)  and  4.1-5  (solids).
Whether or  not  a  stream  must be. controlled will depend upon  its  size,  the
quantities  and   characteristics   of  components,  their  allowable limits  if
released  into  the   environment,  and  the  disposition  of  the  stream  in  an
integrated plant design.

     Tables 4.1-2,  4.1-4,  and  4.1-6  list  the  major   constituents   in  the
streams.  The streams, are  likewise  divided  into  gases,  liquids,  and solids
based on  their  physical  characteristics.  These  tables summarize the data
presented  in  Section 4.2, allowing  for  a quick  comparison of  the  streams.
                                     87

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-------
4.2  MAJOR STREAM COMPOSITIONS

     Data on  the TOSCO II retorting process and product  upgrading  are  avail-
able  in several  documents  published  by  the  Colony Development  Operation.
Most  of the  data  used in  this manual  have  been obtained  from the earlier
24 TPSD  pilot plant  and  a  later  1,000  TPSD  semi-works plant which operated
for over five years on the Colony  site.

     In  the  following sections, major streams  generated  from different plant
operations (see Section 3) are  listed along with their  detailed compositions.
Material balances  for selected streams  (both before  and  after treatment) are
also  presented.   When  detailed information  on stream compositions  or per-
formance of  a control  technology was not  available, calculations were made
on the basis of engineering  analysis.

4.2.1  Material Balance

     The  material   balance  for only  the  TOSCO II   retort  is  presented  in
Table 4.2-1.    This balance  has  been  estimated  from the data  presented  in
Colony's Environmental  Impact  Analysis  (EIA)  (Colony Development  Operation,
1974).   Because  of the  incomplete data  on  upgrading  processes  and various
recycle streams, the material balances were not extended  for the remainder of
the pyrolysis  system or  for the  overall plant.   The commercial; plant would
produce  55,000 BPSD  of  crude  shale  oil based on retorting  66,000 TPSD  of
35 gpt  shale  at 100% Fischer  assay yield.   The  net oil product  after up-
grading and in-plant use would be  47,000 BPSD.

4.2.2  Raw Oil Shale

     Elemental analysis  of  the  organic  portion of the 35 gpt  raw shale has
been reported in Co-lony's EIA and  is presented  in Table 4.2-2.  This- analysis
is representative  of  the  Mahogany zone oil  shale that Colony has proposed to
retort and,  therefore, it has been used without any modification.  The  amount
of organic oxygen  was not reported in the EIA; hence, it was calculated from
the  analysis   of  kerogen  (Stanfield,  et at.-,  1951).   Moisture content  was
calculated from the amount of foul water obtained during pyrolysis of the raw
shale and from the sealing  steam  added to the retort.  Table 4.2-3 indicates
an approximate  mineral  analysis  of the  raw  shale as  presented  in the EIA.
This analysis is useful for  determining the extent of carbonate decomposition
during  retorting  and in  calculating the  theoretical  weight of  processed
shale.   Trace elemental distribution in representative raw shale samples from
the Colony mine is  indicated in Table 4.2-4.

     Raw Shale Leachate—

     Recently, some literature  on  column leaching of Colorado oil  shales has
been published (McWhorter, 1980).  Although the quality of field leachate may
not be  identical to the  leachates obtained from laboratory leaching columns,
the results  from this reference are presented in Table 4.2-5.
                                     125

-------
         TABLE 4.2-1.  GROSS MATERIAL BALANCE FOR TOSCO  II RETORT3
Material In                       .                        Flow, 103 Ib/hr

Raw Shale                                                      5,500

Steam to Retort                                                  150

                            '',"'".''.'  Total In           . 5,650

Material Out                                              Flow, 10s Ib/hr
Processed Shalec
Retort Gas . .
Foul Water6
Crude Shale Oilf
4,450
'240
210
750
                                           Total Out           5,650
  The material balance is around the TOSCO II retort only.  It does not
  include the balance for the entire pyrolysis system.  The balance is based
  on 66;000 TPSD of 35 gpt shale retorting at 100% Fischer assay efficiency.

  Some steam is added to the retort to control the dew point of the
  pyrolysis vapors and also to seal the rotating joints.

c Dry basis.

  Only C4 and lighter components are included in the retort gas.

  The foul water includes the steam added to the retort.  The moisture
  contribution from the raw shale is approximately 60 x 10s Ib/hr;.

  The oil quantity given is for the product before upgrading.   It represents
  55,000 BPSO of crude oil.

Sources:  DRI estimates based on data from Colony Development Operation,
          1974.•
                                     126

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               TABLE 4.2-2.  ORGANIC COMPOSITION OF  RAW  SHALE
                                  (Stream 1)

Component
Raw Shale
Hydrogen (organic)
Moisture
Oxygen (organic)
Nitrogen (organic)
Carbon (organic)
Sulfur (total)
Weight
Percent
100.00
2:i2
1.36
1. 11
0.51
16.53
0.80
Mass Flow,
103 Ib/hr*
5,500
117
75
61
28
909
44
Flow,
103 Tb-moles/hr
' -"
116. 1
4.2
3.8
2.0
75.7
1.4

* Based on 66,000 TPSD of 35 gpt raw oil shale retorting at 100% of Fischer
  assay yield.

Source:  DRI estimates based on data from Colony Development Operation,
         1974, and Stanfield, et al. , 1951.


         TABLE 4.2-3.  APPROXIMATE MINERAL ANALYSIS OF RAW OIL SHALE
                                 (Stream 1)


                                                            Weight
          Component                          '               Percent

          Dolomite, CaMg(C03)2                                 32

          Calcite, CaC03                                       16

          Quartz, Si02                                         ,15

          Illite, K20-3Al203-6SiOa'2H20                        19

          Albite, NaAlSi3Q8                                    10

          Microcline, KAlSi308                          .6

         .Pyrite, FeS2                                          1,

          Anal cite, NaAlSi206-H20                             	1

               TOTAL                                          100


Source:  Colony Development Operation, 1974.

                                     127

-------
              TABLE 4.2-4.
TRACE ELEMENTAL ANALYSIS OF RAW SHALE
      (Stream 1)                     :
Element
As
B
Be
Br .
Cl
Co ...
Cr
Cu • '
F
Ga
Ge
Li
Mn
Ni
Rb
•Sc
Sfr
Sr
Ti
V
Y
Zn
Concentration
(ppmw) Element
7.2 (0.11)a
140
35
0.01
,72
39
49
15
1,700
2.2
0.40
850
34
11
29
2.4
0.08
69
570
29
1.2
13
Ag
Ba
Cd
Ce
Cs
Eu
I
In
La
Mo
Nb
Nd
Pd
Pr
Rh
Ru
Sb
Sm
Sn
Te
Zr

Concentration
(ppmw)
<0.01
32
0.14
1.6
1.2
0.12
<0.01
L
Standard
1.4
4.9
3.4
1.2
<0.1
0.25
<0.1
<0.1
0.39
"0.44
0.11
<0.1
9.3

Element
Au
Bi
Gd
.Dy
Er
Hf
Hg ,
Ho
Ir
Lu
Os
Pb
Pt
Re
Ta
Tb
Th
Ti
U
W
Yb

Concentration
(ppmw)
<0.1
0.36
0.40
0.40
0.27
<0. 1
<0. 1
0.07
<0. 1
<0. 1
<0. 1
10
<0.1
<0.1
0.04
0.07
0.77
. 0,14
0.99
0.42
0.25


a Quantity
b
in parentheses
"; -
( ) is

water soluble.
.




  Because of its presence as a standard, it cannot be measured in the
  sample.                                                    •

Source:  Colony Development Operation, 1974.
                                     128

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4.2.3   Processed  Shale
     TOSCO  II  processed  shale has  been  analyzed  for  chemical  as  well  as
physical  properties  (Colony  Development  Operation,  1974).   The  reported
chemical  composition,  including  organic  elemental   analysis,   is  shown  in
Table 4,2-6.  The quantity  and composition  of  the processed  shale,  derived  by
material  and elemental  balances,  are presented  in Table 4.2-7.'   It can  be
seen  that the  two  tables  differ  in  terms  of organic elemental 'composition.
Since a fairly  good balance between  inputs and outputs  has  been  obtained for
the TOSCO II process, the composition obtained by material balance  is  used  in
calculating  mass flows.    Some  of the  physical  properties  are  reported  in
Table 4.2-8.
         TABLE 4.2-6.  REPORTED ANALYSIS OF TOSCO  II  PROCESSED SHALE3
                                  (Stream 27)
                                                            Weight
          Component                                         Percent
          Hydrogen (organic)                                  0.44
          Oxygen (organic)                                     NR
          Nitrogen (organic)                                  0.35
          Carbon (organic)                                    4 .'49
          Sulfur (total)                                      0.76
          Na20                                                8.68
          K20                                                 3.28
          CaO                                                15.80
          MgO                                                 5.31
          A1203                                               6.80
          Si02                                               33.00
 .         Fe203                                               2.52
          C02  ,                                              20.92
          Loss on Ignition at 900°C                          27.60

a Dry basis.
  NR = Not reported.
Source:   Colony Development Operation, 1974.
                                     130

-------
                TABLE 4.2-7.  COMPOSITION OF  PROCESSED  SHALE
                                  (Stream 27)

Component
Processed Shale*
Hydrogen (organic)
Oxygen (organic)
Nitrogen (organic)
Carbon (organic)
Sulfur (total)
Weight
Percent
100.00
0.29
0.09
0.24
3 . 46
0.52
Mass Flow,
103 Ib/hr
5., 170
15
5
13
179
27
, Flow,
103 Ib-moles/hr
•
14. 9
0.31
0.9
14.9
0,8-

* Moisturized to a 14% water content.

Source:  DRI estimates based on material and elemental balances using data
         from Colony Development Operation, 1974.
        TABLE 4.2-8.  PHYSICAL PROPERTIES OF TOSCO II PROCESSED SHALE
                                 (Stream 27)
Parameter
Unit
Quantity
Geometric Mean Size

  Geometric Standard Deviation
 cm
Source:   Ward, Margheim and Lof, December 1971.


                                     131
 0.007

 3, 27
Permeability
Bulk Density
Solids Density
Porosity
Maximum Size .
Minimum Size
cm2
g/cc
g/cc
'
cm
cm
2.5 x 10~10
1.30
2.49
0.47
<0.476
>0. 00077


-------
      Processed Shale Leacnate—

      Trace element analysis performed on runoff and leachates from field test
 plots of  TOSCO II  processed shale  is presented  in  Table 4.2-9  (Metcalf  &
 Eddy, October 1975).  For  comparison,  the  trace element levels found in some
 naturally  occurring waters  are also presented in the table.

      teachable organics  from the  same  batch of processed shale  were  deter-
 mined in laboratory leaching experiments (Metcalf & Eddy,  October 1975).   The
 results  of these  experiments are presented  in Table 4.2-10.

      Some  of the  leachable  inorganics  from the TOSCO  II processed shale were
 determined  in a  separate  laboratory  experiment  (Ward, Margheim and  Lof,
 December 1971) and these results are presented in Table 4.2-11.

 4.2,4 Crude Shale Oil  and  Upgraded Oil  Products

      Fractionation  of  pyrolysis  vapors results  in  product breakdown  into
 retort  gas,  water,  naphtha,  gas  oil  and  bottoms  oil.   The properties  and
 elemental  compositions  of  the  last  three oil  fractions are  presented  in
 Table 4.2-12.   Since product  upgrading  is  considered  an integral  part  of the
 process, the properties of  the hydrotreated shale oil  obtained as;  a result of
 upgrading  are included  in Table 4.2-13;  quantities  and estimated'compositions
 of other  products of  the  upgrading operations  are listed  in  Table 4.2-14.
 The gross  mass flows in these latter two tables do  not agree.   This is  due to
 conversion  of some  liquid  products into  gaseous products  upon  upgrading
 treatments,   the  production of  crude shale oil is  55,000 BPSD,  and the yield
 is 100%  of  Fischer  assay.   The crude oil  is  upgraded to produce  47,000 BPSD
 of syncrude  and  4,330  BPSD of  liquid petroleum gas.   During the  upgrading
 process, 3,100 BPSD of C4  liquids  are also produced;  this product is used as
 process  fuel in the preheating system.

.4.2.5 Retort Gas

      The analysis of the raw retort gas as it emerges  from  the oil  recovery
 system (pyrolysis fractionator) has  been reported  in  Colony's EIA.   However,
 the net  gas entering the gas recovery and  treating units  is  different  due to
 addition  of gaseous overheads  from  the other  upgrading units.   While  the
 exact compositions of these  additional  streams are not known, an  attempt was
 made to  determine the  gross  addition to  the  raw  retort gas by  material, as
 well  as  elemental balances  for  the inputs  and outputs to  the process.   These
 analyses, are  shown  in  Table 4.2-15.   Also,  the retort gas   contains  sulfur
 .species  other than H2S;  the content of these  species  in  the fuel  gas,  after
 treatment  by .the  diethanolamine  (DEA)  process, has been measured  in a pilot
 plant study and  it  is  listed in Table 4.2-16  (Colony  Development Operation,
 January  26,  1979).  Since the  removal  efficiency of the amine  system  is not
 known for  these compounds,  their exact amounts in the  untreated gas cannot be
 calculated.   It  is  likely,  however,  that since diethanolamine  (DEA) removes
 COS  quite  efficiently,  the amount  of COS  in  the untreated  gas could  be
 significantly higher than that  found in the treated gas.  The  composite gas
 to the gas  recovery  unit  is fractionated into Ci/C2  and  C3/C4 gases.   Since
 the  compositions  of  these  fractions   are  not  documented  by  Colony,  an

                                      132

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            TABLE 4.2-14.  PROPERTIES OF OTHER PRODUCTS FROM UPGRADING
                            OF TOSCO II CRUDE SHALE OIL
                         (Streams 60 or 77, 103, 108, 129)

Component
Hydrogen
Weight Percent
Mass Flow, 103 Ib/hr
Flow, 10s Ib-moles/hr
Moisture
Weight Percent
Mass Flow, 103 Ib/hr
Flow, 10s Ib-moles/hr
Oxygen
Weight Percent
Mass Flow, 10s Ib/hr
Flow, 103 Ib-moles/hr
Nitrogen
Weight Percent
Mass Flow, 103 Ib/hr
Flow, 10s Ib-moles/hr
Carbon
Weight Percent
Mass Flow,' 103 Ib/hr
Flow, 103 Ib-moles/hr
Sulfur
Weight Percent
Mass Flow, 10? Ib/hr
Flow, 10s Ib-moles/hr
Cokea
(Stream 103)
3.19
2.1 .
2.1
7.00
4.7
0.3
2.0
1.3
0.1
5.96
4.0
0.3
81. 48
54.6
4.5
0.37
0,2
0.01
Total Mass Flow, 103 Ib/hr 67
Diesel
(Stream 108)
15.0
0.9
0.9
i
—
—
85.0
5.1
0.4
' .
6
Ammonia0 Sulfur0
(Stream 129) (Streams 60 or 77)
17.65
2.1
2.1
;. -. V.E '.
—
82.35
9.9 , ' — .
0.7
—
100.0
16.5-17.0
0.5
11 16.5-17.0

  Analysis of coke estimated from elemental and material balances based on data
  from Colony Development Operation, 1974, and Whitcombe and Vawter, March 1975.

  Analysis of diesel assumed.

c Quantity of NH3 and .S from Colony Development Operation, 1974.

Source:  DRI estimates based on data from Colony Development Operation, 1974, and
         Whitcombe and Vawter, March 1975.
                                       138

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 arbitrary  proportion of  the constituents  between the  two  fractions is  as-
 sumed.   The   resulting   compositions   are  presented  in  Table 4.2-17.    The
 estimated  compositions  of treated gaseous  products,  obtained by material  and
 elemental  balances, are  presented in  Tables  4.2-18  through  4.2-21.  Calcu-
 lations  are performed  separately for  the  C!/C2 and C3/C4  fractions  treated
 either by  the  amine process  or  by the  Stretford  process.


         TABLE 4.2-16.  SULFUR  CONTENT OF THE  AMINE TREATED  FUEL:GAS
                                  (Stream 33)                     ,
Component
H2S
CHgSH
C2H5SH
i-C3H7SH
COS
CS2
Concentration,
ppmv
130 .
20
10 ;
5
135 .
i
nil
              TOTAL                         .            300
Source:  Colony Development Operation, January 26, 1979.


4.2.. 6  Flue Gas                       ,                           /

     The total emissions from the three case studies were estimated, in part,
using  calculated  flue  gas  compositions.   The task  of  calculating these data
is complicated by the presence of the upgrading facility.
                              -. '    •                              i
     Treated  fuel  gas (molecular  weight approximately  16)  is the principal
fuel used  in  most furnaces and in the boiler; it is also consumed chemically
in  producing  hydrogen.    The  fuel  gas,  mostly  methane,   is recovered  by
fractionating  the  gases,  Ci to  C4,  after they have been  separated from the
liquid products.  The  total  content of H2S in the mixture of  gases must also
be  fractionated  between the various cuts to  obtain the quantity  in  the Ct
fraction..  Calculations  were made  to  estimate the  distribution  of organics
and H2S  in order to  calculate  flue gas compositions.   Going  from  the amine
process to  the Stretford  process,  the composition of  this  treated gas also
must be  changed  to reflect a  different removal  efficiency  for H2S,  other
sulfur species and C02.  While the amine process removes most of the C02, the
Stretford process removes very little,  changing the heating value and size of
the treated streams.                    ;                           ,


                                     140;

-------
     TABLE 4.2-17.
     ESTIMATED COMPOSITIONS OF CjVCg AND C3/C4 FRACTIONS
               (Streams 32, 35)
Component
MWt
 Compressed
Composite Gas
  109 ib/hr
Ci/C2 Fraction'
  (Stream 32)
     Ib/hr
C3/C4 Fraction0
  (Stream 35)
     Ib/hr
H2S
RSHb
COS
hV
CO
C02
CH4
C2H4
C2HS
C3H6
CsHg
C4H8
i-C4H10
n-C4H10
TOTAL
Total H
Total 0
Total C
Total S
34
56
60
2
28
44
16
28
30
42
44
56
58
58





12.32
0.02
. 0.12
3.59
8. 38
79.07
52.51
34.73
20.16
26.48
13.03
16.24
0.98
9.54
277.17
36.72
62.33
166.46
11. 67
12,197
14.5
120
3,590
8,380
79,070
52 ,510
34,383
19,958
1,324
652
—
—
—
212,198.5
26,648
62,326
111,675
11,549
123
10.1
1.0
,
—

.
347
202
25,156
12,379
16,240
980
9,540
; 64, 978.1
10,077
0.3
54,780
122

 . The compositions of  C!/C2  and C3/C4 fractions  are  not documented;  there-
  fore, it  is  assumed  that 1% each  of  H2S,  COS,  C2H4, and C2H6 :and 40% of
  RSH go  into the C3/C4  fraction and 5%  of  C3H6 and C3H8 remain  in  the
  C;j/C2 fraction.  Other  components  are not proportionated between the two
  fractions.
h
  Assumed before treatment concentration of RSH 35 ppmv and COS 270 ppmv.

Source:   DRI estimates based on data from Colony Development Operation,
         1974.
                                     141

-------
        TABLE  4.2-18.
FRACTION RETORT GAS AFTER AMINE PROCESS
 (Streams 32, 33)
Component
H2S
RSH
COS
H2
CO
C02
CH4
C2H4
C2H6
CsHg
C3H8
TOTAL
MWt
Total H
Total 0
Total C
Total S
MWt
34
56
60
2
28
44
16
28
30
42
44





Untreat
Gas
(Stream
Ib/hr
12,197
14
120
3,590
8,380
79,070
52,510
34,383
19,958
1,324
652
212,198.
22




Heating Value, LHV Btu/lb
ed
32) Mass
%
0.0266
.5 0.0119
0.0489
2.95
6.89
0.65
43.15
28.25
16.40
1.09
0.54
.5 100.01
.40 16.
21.31
4.43
74.2
0.06
(Btu/SCF)
After Amine Absorber
(Stream 33)
Mole
%
0.0130
0.0035
0.0135
24.47
4.08
: 0.24
44.74
16.74
9.07
0.43
0.20
100.00
59




20,555 (895)
Mass Flow,
Ib/hr
32.4*
14.5
59.5
3,590
8,380
790
52,510 .
34,383
19,958
1,324
652
121,693.5

25,932.9
5,391.0
90,296.6
74.0

Flow,
Ib-moles/hr
0.95
0.26
0.99
1,795.0
299.29
• 17.95
3,281.88
1,227.96
665.27
31.52
14.82
7,335.89

25,932.9
336.9
7,524.7
2.3


* Based on after treatment H2S concentration of 130 ppmv as given'by Colony
  Development Operation, January 26, 1979.

Source;   DRI estimates based on data from Colony Development Operation, 1974
         and January 26, 1979.
                                     142

-------
TABLE 4.2=19.
                                 FRACTION RETORT GAS AFTER STRETFORD PROCESS
                                  (Streams 32,  34,  128)                  ;
Component
H2S
RSH
COS
H2
CO
C02
CH4
C2H4
C2H,B
CsHg
C3H8
TOTAL
MWt
Total H
Total 0
Total C
Total S
MWt
34
56
60
2
28
44
16
28
30
42
44





Heating Value,
Untreate
Gas
(Stream ;
Ib/hr
12,197
14.
120
3,590
8,380
79,070
52,510
34,383
19,958
1,324
652
212,198.





LHV Btu/lb
Ammonia
5d Recovery
Overhead
!2) (Stream 128) Mass
Ib/hr %
5,792 0.0047
5 — 0.0022
0.0520
1.83
4.27
888 38. 33
26.78
17.54
10.18
0.68
0.33
5 6,680 100.00
.. 21.
13.17
30.52
56.28
0.035
(Btu/SCF) 12,701 (610)
After Stretford Process
(Stream 34) ;
Mole
%
0.0030
0.0009
0.0188
19.89
3.32
18. 93
36.36
13.60
7.37
0.35
0.16
100.00
72





Mass Flow,
Ib/hr
9.2b
4.4C
102b :
3,590
8,380 '•
75,160b
52,510
34,383
19,958
1,324
652
196,072.6

25,933
59,485 .
110,590
66

Flow,
Ib-moles/hr
0.27
0.08
.1.70
1,795.00
299.29
1,708.18
3,281.88
. 1,227.96
665.27 .
31.52
14.82
9,025.97

25,933
3,718
9,216
2

  Gomposltion presented is for compressed and cooled overhead vapors before they enter
  the Stretford absorber.                                                   .

  Based on after treatment concentration of 30 ppmv H^S as given by Peabody Process
  Systems, Inc., February 1981.

c Approximately 70% of RSH, 15% of COS, and 6% of C02 are assumed to be removed by the
  process.

Source:   DRI estimates based on data from Colony Development Operation, 1974, and
         Peabody Process Systems, Inc., February 1981.
                                          143

-------
        TABLE 4.2-20.  C3/C4  FRACTION  RETORT  GAS  AFTER AMINE  PROCESS
                               (Streams  35,  36)                   :

Untreated
Gas
Component
H2S
RSH
COS
C2H4
CgHe
£3^5
CsHg
C4H8
i-C4H10
n-C4H10
TOTAL
MWt
Total H
Total 0
Total C
Total S
Heating Val
MWt
34
. 56
60
28
30
42
44
56
58
58





ue, LHV
(Stream 35) Mass
Ib/hr . %
123
10.
1.
347
202
25,156
12,379
16,240
980
9^540
64,978.





Btu/lb
0.0094
I 0.0156
0 0.0008
0.53
0.31
38.78
19.09
25.04
1.51
14.71
1 100.00
47.
15.52
0.0003
84.47
0.0005
(fitu/SCF)
After Amine Absorber
(Stream 36)
Mole Mass Flow,
% Ib/hr
0.0130
0.0131
0.0006
0.90
0.49
43.68
20.52
21.15
1.23
12.00
100.00
30




19,702 (2,458)
6.1
10.1
0.5*
347
202
25,156
12,379
16,240
980
9,540
64,860.7

10,065.2
0.2
54,778.0
11.2

Flow,
Ib-moles/hr
0.18
0.18
0.008
12.39
6.73
598.95
281.34
• 290.00
16.90
164.48
1,371.16

10,065.2
.0.01
4,564.8
0.35


* A 50% removal of COS is assumed.

Source:  DRI estimates based on data from Colony Development Operation,
         1974.                   .                                 :
                                     144

-------
       TABLE 4.2-21.   C3/C4  FRACTION RETORT GAS AFTER STRETFORD PROCESS
                               (Streams  35, 72)
Component
H2S
RSH
cos •
C2H4
£•2^6
,CsH6
CsHg
C4H?
i-C4H10
n-C4H10
TOTAL
MWt
Total H
Total 0
Total C
Total S
MWt
34
56
60
28
30
42
44
56
58
58





Heating Value, LHV
Untreat
Gas
(Stream
Ib/hr
123
10.
1.
347
202
25,156
12,379
16,240
980
9,540
64,978.





Btu/lb
;ed
35) Mass
1 %
0.0022
1 0.0109
0 0.0013
0.54
0.31
38. 79
19.09
25.04
1.51
14.71
1 100.00
47.
15. 52
0.0003
84.47
0,0005
(Btu/SCF)
After Stretford Process .
(Stream 72)
Mole Mass Flow,
% Ib/hr
0.0030
0.0095
0.0010
0.90
0.49
43.69
20.52
21.15
1.23
12.00
99.99
30




19,702 (2,458)
1.4a
7.1b
0.9b
347
202
25,156
12,379
16,240
980
9,540
64,853.4

10,069.0
0.2
54,778.7
5.4

Flow,
Ib-moles/hr
0.04
0.13
; o.oi
12.39
6.73
598.95
281.34
290.00
: 16.90
164.48
1,370.97

10,063.9 '
; 0.01
: 4,564.5
0.01


  Based on after treatment concentration of 30 ppmv H2S as given by Peabody
  Process Systems, Inc., February 1981.

  Approximately 70% of RSH and 15% of COS are assumed to be removed by the
  process.

Source:   DRI estimates based on data from Colony Development Operation,
         1974, and Peabody Process Systems, Inc., February 1981.
                                     145

-------
     The  calculated flue  gas  compositions  for  the combustion of the  entire
quantity  of fuel gas burned  in  the plant,  as well  as for combustion  of  the
quantities  of  liquids  and crude  shale  oil  burned,  are shown  in Tables  4.2-22
and 4.2-23.  Colony  is planning to  use  crude shale  oil  in  the ball heater  and
thermal oxidizer because approximately 95%  of the  S02 in the preheat  system
flue  gas  is claimed to be  removed by  adsorption  on  the raw shale (Colony
Development  Operation,  1977).  This  eliminates the  need for using  upgraded
oil  in the .preheat  system.   If judged appropriate,  the  fuel balance  may be
shifted toward the  use  of upgraded oil  after  reaching full  capacity  opera-
tion.          •

     The   materials  balance   around  the   Claus   unit   is  presented  in
Table 4.2-24.   The  acid gas . from the  amine regenerator  is the primary feed
stream to the  unit.  In addition, the overhead from the ammonia recovery unit
and the tail gas recycle stream from the Wellman-Lord  unit are introduced.  A
metered amount of  air is added to  cause oxidation  of  enough  H2S to provide a
2:1  (H2S:S02)  stoichiometric for a subsequent  catalytic  reaction, producing
elemental  sulfur.  The unrecovered  sulfur compounds in  the Claus'tail gas  are
then fed to the Wellman-Lord unit for further recovery.

     The  unreacted  H2S in the Claus  tail  gas is converted to S02 by  intro-
ducing  fuel  and air  in  the  Wellman-Lord  incinerator.   The  
-------
                TABLE 4.2-22,   CALCULATED FLUE GAS COMPOSITIONS FOR FUELS BURNED IN THE
                                  COLONY PLANT, CASE STUDIES A AND B
                           (Streams 18, 19, 24, 91, 104, 118, 119, 125, 179),
Fuel use
Preheat System:
Incinerator
Ball Heater"
Subtotal
Total Flue Gasc
(after venturi
scrubber, Stream 18)
Steam Superheater
Fuel Rate/Type3
(MM8tu/hr)

510/C4+
102/0 il
474/Fuel Gas
956/011
126/0 11
Combustion Products (103
C02

80.7
16.2
62.8
154.7
314.4
314. 4
20..4
H-20

41.7
7.4
49.3
70.9
169.3
169.3
9.3
N2

414.8
79.4
382.6
759.4
1.636.2
1,636.2
100.1
02

35.6
6.6
31.9
63.3
137.4
137.4
8.3
Ib/hr)
:S02
(Whr)

0.5
86.1
21.6
807.3
915.5
51.0
106.4

NOx
(Tb/lir)

134.3
1,258.7
1.393.0
1,314.8
165.9
  (Stream 24)

Total Flue Gasc
  (after venturi
  scrubber, Stream 19)

Wellman-Lord Process
87/Fuel Gas
                 20.4       9.3      100.1      8.3       94.3      113.4
11.4       9.0       65.5      3.7        4.0
Heaters, Furnaces
  and Boi1er:
Hydrogen Furnace
(Stream 91)
Naphtha Heater
(Stream 125)
Gas Oil Heater
(Stream 118)
Fractionator Reboiler
(Stream 119)
Coker Feed Heater
(Stream 104)
Boilers
(Stream 179)
600/Fuel

9/Fuel

20/Fuel

81/Fuel

62/Fuel

200/Fuel

Gas

Gas

Gas

Gas

Gas

Gas

79.

1.

2.

10.

8.

26.

4

2

7

7

2

5

62.

0.

2.

8.

6.

•20.

4

9

1

4

4

8

484.3

7.3

16.1

65.4

50.0

161.4

40.4

0.6

1.4

5.5

4.2

13.5

27.

0.

0.

3.

2-

7.

4

4

9

8

8

2

82.2

1.3

2.7

11.2

' 8.4

21.6

a The fuel rates and types are obtained from U.S. 001, 1977, and Colony Development Operation, 1977.

b The quantity of NOx is that calculated from the fuel based nitrogen only.

c The quantity of S02 is that remaining after absorption on the shale.  The quantity of NOx  includes
  fixation of atmospheric nitrogen less any NOx absorbed on the shale.

d The combustion products are from burning the fuel only.  See Table 4.2-25 for the total  flue gas
  composition.

Source:' .DRI estimates based on data from Colony Development Operation, 1977, and U.S. 001,  1977.
                                                  147

-------
                   TABLE 4.2-23.  CALCULATED FLUE GAS COMPOSITIONS FOR FUELS BURNED
                                   IN THE COLONY PLANT, CASE STUDY C
                           (Streams 18, 19, 24, 91, 104, 118, 119, 125, 179)
Fuel, Use
Preheat System:
Incinerator
Ball Heaterb
Subtotal
Total Flue Gasc
Fuel Rate/Type3
(MMBtu/hr)

510/C4*
102/0 il
625/Fuel Gas
805/01 1
Combustion Products (103
C02

80.7
16.2
126.6
108.4
331. 9
331.9
H20

41.7
7.4
80.0
49.6
178.7
178.7
N2

414.8
79.4
614. 2
302.0
1,410.4
1,410.4
02

35.6
6.6
51.2
44.4
137.8
137.8
Ib/hr)
S02
(Ib/hr)

0.5
86.1
41.9
679.8
808.3
45.0

NOx
(Ib/hr)

134.3
1,014.5
1,148.8
1,084.3
  (after venturi
  scrubber, Stream 18)
      Superheater
  (Stream 24)

Total Flue Gasc
  (after venturi
  scrubber, Stream 19)

Heaters, Furnaces
  and Boiler:
                          126/0il
20.4
20.4
           9.3
           9.3
                    100.1
100.1
           8.3
                               8.3
106.4
                                         94.3
                                                                                               165.9
                                                   113.4
Hydrogen Furnace
(Stream 91)
Naphtha Heater
(Stream 125)
Gas Oil Heater
(Stream 118)
Fractionator Reboiler
(Stream 119)
Coker Feed Heater
(Stream 104)
Boilers
(Stream 179)
600/Fuel
9/Fuel
20/Fuel
81/FueT
62/Fuel
136/Fuel
Gas
Gas
Gas
Gas
Gas
Gas
97.
1.
3.
13.
10.
22.
5
5
3
2
1
1
62.4
0.9
2.1
8.4
6.5
14.1
484.
7.
16.
65.
50.
109.
9 .
3
2
5
1
9
40.4
0.6
1.4
5.5
4.2
9.2
33.
0.
1.
4.
3.
7.
0
5
1
5
4
5
82.2
1.3
,2.7
11.2
8.4
14.7
  The fuel rates and types are obtained from U.S. 001, 1977, and Colony Development Operation, 1977,
  except the fuel savings due to decreased steam load and substitution of Stretford in, place of amine/
  Claus/Wellman-Lord required that the fuels to the ball heater be redistributed.  The. fuel savings
  are equivalent to 600 8PSD of crude oil.

  The quantity of NOx is that calculated from the fuel based nitrogen only.

c The quantity of S02 is that remaining after absorption on the shale.  The quantity of NOx includes
  fixation of atmospheric nitrogen less any NOx absorbed on the shale.                ;

Source-.   DRI estimates based on data from Colony Development Operation, 1977, and U.S. DOI, 1977.
                                                 148

-------


















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-------
            TABLE 4.2-26.   INORGANIC SPECIES IN TOSCO II FOUL WATER
                                  (Stream 29)
Component
Ca++
Mg++
Na+
K*
HCOi
C0|
•CT
F~
CN-
Si
Other Components
Fe
B
Ce, Ag, Sr, Rb, Br, Se, 'AS,
In, Cu, Ni, Mn, Ti , P, Al
Pb, Ba, Mo, Zr, Co, Cr, Li
Concentration, mg/1
6
2
5
0.4 ;
—
— •
5
0.3 '
12
1.3
Range, mg/1
. 1 - 10 ' '
0.1 - 1.0 ,
0.01 - 0.1 ..
0.001 - 0.01
Source:   Haas, June 1979.
                                     151

-------
         TABLE 4.2-27.  ORGANIC CONTENT OF GAS CONDENSATE (FOUL WATER)
                                  (Stream 29)

Component
Acids
Phenol s
Bases
Neutral s
TOTAL
TOC
Concentration,
mg/1 • '•
1,710
510
680
1*424
4,324
3,160
Mass % of
Organics
39
12
16
33
100
73

 Source:  Metcalf & Eddy Engineers, October 1975.


      A  small  amount of moisture  is  also removed from  the  retort gas during
 compressing  and after-cooling  operations  in  the  gas  recovery  and treating
 section, and  this  is added  to  the earlier foul water.  Wash  water from the
 coking  operation is  the  last source of  foul  water.   The composition of this
 water  has  been estimated  from  analyses of  bottoms oil  and coked products.
 Table  4.2-28  presents  the  composition  along with  the  gas  condensate compo-
 sition  and  the  resulting  combined  foul   water   stream  composition.   The
 material  balance  around   the   foul   water  steam   stripper   is  given  in
 Table 4.2-29.

      The  sour  water is  obtained  from  the  hydrotreaters  by  washing  the
 hydrogenated  naphtha and  gas oil  with  wash water.  Most of the organically
 bound  nitrogen, oxygen,  and  sulfur  are  reduced  to   ammonia,  water,  and
 hydrogen sulfide,  respectively,  during  the  hydrotreating operation  and are
. dissolved in the wash water to form the sour water.   The potential amounts of
 NH3 and H2S formed  are calculated from the nitrogen and sulfur contents of
 the  naphtha  and  gas  oil  before  and  after hydrotreating.   Sour water  is
 processed  by  the  ammonia  recovery  unit  to  obtain   ammonia  and  hydrogen
 sul fide.  Most  of  the processed  sour water  is recycled back  to the hydro-
 .treaters,  but a small  bleed  stream is  blown  down and  combined with  the
 stripped foul  water.   In  Case Study C,  the overhead  vapors  from the  foul
 water stripper (which are  normally fed to the Glaus process) are added to the
 ammonia  recovery system.   This increases  the  ammonia  by-product production
 from 135 TPSD  to  143 TPSD.   The  compositions  of  the sour  water,  processed
 sour  water,   and   ammonia  recovery   overhead  vapors  are   presented  in
 Tables 4.2-30 and 4.2-31.

 4.2,8  Stripped Foul  Water Treatment

      One technology  for cleaning  the foul water after  stripping—biological
 oxidations-was  examined.   This  standard  treatment  technology provides  some


                                      152

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.additional  control of organics  prior to use of the water for processed shale
 moistening.   Table 4.2-32  presents  the material  balance for  the  biological
 oxidation plant;  it shows  that  the  overall organics destruction possible  by
 biological  processes  is  expected to  be less than 50% efficient.

 4.3  POLLUTANT CROSS-REFERENCE TABLES

      Tables  4,3-1 through  4.3-3  list some pollutants of concern,  by  medium,
 and provide a cross-reference to  the numbered streams in this  manual.   Many
 of these pollutants are trace constituents,  and measurements to identify  or
 quantify them in  oil shale processing related streams have  never  been made.
 Those pollutants which have been  identified in the plant streams  are cross-
 referenced  to the detailed  composition tables.   Engineering  judgment was used
 in  identifying  other  probable  pollutants.    The  entry  for  "unknown" (U)
 indicates that no testing  has been  done and the presence  of the pollutant  is
 unlikely.    Judgment  was   also   used  in   specifying   the   pollutants  which
 definitely  should not be present.
                                     157

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                                  SECTION 5

                        POLLUTION CONTROL TECHNOLOGY            ''.


     This section presents an inventory of pollution control technologies and
discusses, in depth, some representative controls for each medium  (air, water
and  solid waste).   The inventory expands  beyond describing the technologies
that have  been  proposed by developers of  the TOSCO II  process.   That is, it
discusses  alternate and additional  technologies  that  provide varying levels
of  control.  Although  the  inventory is  quite extensive,  other possibilities
may  exist and  should  not  be excluded  from consideration.   Changes  in the
design  of   the  plant  complex,  changes   in   the  assumptions;  made  (see
Section 1.5),  and/or  improved  data  from  future  testing could lead  to . the
selection of different  controls.

     Each subject area  for control (e.g., particulate control) begins with an
inventory of available technical  approaches, or technologies.  Promising new
control  technologies  not yet applied commercially,  even  in  related indus-
tries,  are  also included in  the inventory but are  not described  in detail.
Such new technologies may be applicable to the oil shale  industry  if they are
sufficiently developed  and  tested in the future.   The  inventory is followed
by a discussion of  the most important considerations in  selecting a control.
Finally,  a  more detailed analysis  of performance and  cost is presented for
the  control  technologies  that  have been  considered   by Colony Development
Operation in conjunction with the TOSCO II process (see  Sections 2 and 3 for
descriptions of the case studies which include  the proposed processes and
technologies).                                                   ' ,  .    .

     The  detailed  analysis  seeks to estimate pollution  control  performance
and  cost.   Performance estimates generally require no more than  conceptual
designs;  however,  the . reliability  Of  the  performance  estimates  varies
depending  upon  the  application.   The  estimates  should  be  highly reliable
where a proven  technology  is  applied to a stream for which experience exists
(e.g., flue gas desulfurization)  but may be  much  less  accurate for controls
which require testing  and which are applied to unconventional streams (e.g.,
biological oxidation).   All  performance levels  are given  for instantaneous
control and reflect  optimal  operation,  which may be higher than the average
level of performance actually achieved.   All cost estimates  are; in mid-1980
dollars and.  are taken  to  the  level  of  detail  believed  to be  necessary  to
achieve ±30%  accuracy.  This  level  of accuracy is  based on  the  cost  of
equipment already built and  operating in related industries.     ;
                                     167

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5.1  AIR POLLUTION CONTROL

     As  in other industrial  and oil  shale  operations,  the TOSCO II plant—
from mining activities to final  product  storage and transfer—will generate
particulate and  gaseous  component emissions.  The primary air emissions are:

     •Particulates, TPM                           .   '        :

    . *    .Sulfur Dioxide, S02

     •   .Nitrogen Oxides., NOx
     •••'"   Carbon Monoxide, CO

     *    .Hydrocarbons, HC.
                                  • •                              i
     This  section  describes the  current,  commercially available alternative
systems  for controlling  the above  primary  pollutants.  ..The  following sub-
sections provide inventories of control technologies for each of the air pol-
lutants, a discussion of advantages and  disadvantages,  and important points
to consider in selecting a particular  technology.   Performance,  design, and
cost data for the leading technologies examined are also presented.

5.1.1  Particulate Control

     Particulate matter  is  generated during the mining, crushing, conveying,
and processing of oil shale.   Particulates are emitted from fugitive sources
such as  conveyor  belts   and  from  point  sources  such  as  flue;gas stacks.
Federal and State standards and regulations limit these particulate emissions
because  of  their  potentially  hazardous  effects  on  human  health and the
environment*                                                     i

     Inventory of Control Technologies—

     As  shown  in Figure 5.1-1,  particulate  control can be  divided into two
general categoriest

     »    Control of point sources                               ;  •
     »    Control of fugitive sources.

     The particulate matter  from  a point  source  is  confined :within  some
equipment  boundaries  and is  controlled  by passing  the  dust-laden  stream
through a  control device.   Fugitive particulate matter  is  unconfined  and is
generally controlled by wet suppression techniques which are generally not as
efficient  as  the point  source control  techniques.   Table 5.1-1  presents  a
listing and review of particulate control  technologies.

     Control of point sources.   There  are  two  primary  classes of particulate
control  equipment  for point  sources:   dry  and wet.  Both classes  offer
processes  that  are   feasible  for  particulate  control  in oil  shale applica-
tions.   Dry dust collectors  can only be used with dry dusts.   Sticky partic-
ulates  tend  to clog  the  dry  collector and reduce its performance.   In such
cases,  wet collectors are used.
                                     168

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('ARTICULATE
  CONTROL
ECHNOLQG1ES
                                                DRY
                                             COLLECTORS
    WET
COLLECTORS
                       CONTROL OF
                        FUGITIVE
                        SOURCES
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                                          SUPPRESSION
                                                                    : VENTURI
                                                                    SCRUBBER
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                                                                  PLATE SCRUBBER
                                                                      SPRAY
                                                                      TOWER
                                                                    CYCLONE
                                                                    SCRUBBER
                                                                  ELECTROSTATIC
                                                                  PRECIPITATOR
SOURCE- SWEC
                 FIGURE 5.1-1  PARTICULATE CONTROL TECHNOLOGIES

                                       169

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     Dry  particulate  removal   from gases  can  be  accomplished  by several
methods  (shown in  Figure  5.1-1  and reviewed  in Table 5.1-1).   The baghouse
(fabric  filter)  collector operates  by passing  the  dust-laden  gas through a
fabric  network that acts  as  a dust filter.   Its  removal  efficiency is over
99% and  operating, costs are low compared  to  other approaches.   ;The electro-
static  precipitator,  which  also   has  a  high  removal   efficiency,  affords
separation  of  dust  by  passing the  dust-laden gas  through  an   electrostatic
field.   The dust particles  become charged and  migrate  to collector plates.
Another technique is the cyclone separator which operates on the;principle of
centrifugal force.   The dust-laden gas enters the chamber tangentially.  The
dust particles have  a higher inertia than the gas, so they travel to the wall
of  the  cylindrical or conical chamber  and  then  into  a  receptacle.   The
removal  efficiency  for cyclones   varies  from  50  to  90  percent.   In  the
impingement process, the dust-laden gas impinges on a body which:collects the
particles as the  gas deflects  around the  body.   The removal efficiency is 0
to 80  percent.   The simplest  mechanical  separator  is  the settling chamber.
The dust just settles  to  the  bottom  of the  tank due  to  its  heavier mass,
resulting in a removal  efficiency from 0 to 50 percent.

     Wet  collectors  require  mixing  the  dust-laden  gas   with; an  aqueous
solution  that  captures and  removes the dust particles  from the gas stream.
Examples  of  such,  equipment  are  shown  in  Figure  5.1-1  and   described  in
Table 5.1-1.   In  the  venturi  scrubber,  the  gas  and  liquid pass  through  a
throat at  a high  velocity, promoting collisions  between  the dust and liquid
droplets.   These  units require a  high  pressure drop (~50  in.  H20)  and have
removal  efficiencies of greater than 90 percent.  Another  wet  scrubber,  the
impingement-pi ate  type, consists  of a perforated tray with an: impingement
baffle  located above each perforation.   A liquid level  maintained  over the
trays  collects the  dust  as  the  gas  passes  through it.   These  units  are
similar to the venturi  scrubber and have about the same removal  efficiencies;
however,  the  process  requires a  larger  pressure drop  across the  plates.
Another type of wet scrubber is the spray  tower;  it utilizes cquntercurrent
spraying of liquid  droplets  to remove the  dust  particles by impaction at an
efficiency of 50 to 80 percent.  The operation of the wet cyclone scrubber is
similar to  that of  the dry cyclone  except  liquid is introduced jinto the gas
stream, removing  the dust  by inertia!  impaction.  The  removal  efficiency of
the wet cyclone  is 50 to 75 percent.   The  wet  electrostatic precipitator
operates under the same principle and at about the same efficiency as the dry
precipitator.

     Control of fugitive sources.    Wet  dust suppression can be  'used for the
containment of fugitive dust.   This process   consists  of spraying  the  dust
source with water or a foam suppressant which traps  the dust and prevents it.
from becoming  airborne.  The  foam  sprays are  relatively inexpensive, consume
less water  than pure water sprays, and are very effective.   In a foam spray
system,  foam   is  produced  by  pumping  a  mixture  of  water and  a  surfactant
through an air atomizing nozzle which produces small  bubbles of approximately
100 to 200  microns.   These  wet  bubbles  are broken  by contact with  dust,
coating the  particle.   The  foam  is only effective when  applied directly to
the source, such  as on a conveyor,  or  to  a falling stream of material, such
as at  a  conveyor transfer  point.   Once the  wetted dust  agglomerates  with
other particles,  it no longer becomes airborne at subsequent transfer points.

                                     172

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The  suppression  (or  removal)  efficiency  is  95  to  99%  in  terms - of:  the  material
contacted.                                          .       .     •'

      Paving  the  heavily traveled  roads with a hard  surface and providing
vegetative  covers  for the disturbed  areas are  additional  technologies  for
reducing  fugitive   dust emissions.   These  technologies  are described  in
Section 5.3.

      Particulate  Control Technologies Analyzed—                    -

      The  TOSCO II plant- has  two major  areas where particulate  matter  is
produced  and  must be controlled:  (1) raw  shale  mining, crushing,  conveying,
and  storage, and  (2) shale pyrolysis.

      Dry  dust  is generated at point sources,  such  as the primary  and secon-
dary  crushers,  and  at  the  enclosed fine ore  storage area.   For  these point
sources,  baghouses  were examined for particulate  removal  due to their  high
removal efficiency,  relatively low operating costs, and  the dry hature of the
particulate.

      The  flow rates and particulate removal  efficiencies  reported by Colony
(Colony  Development  Operation,   1977)  were   used  as the  design  basis   for
estimating  the  size and cost of the baghouses.  Depending  upon:  the  type  of
dust,  particle  size  distribution,  and  grain loading,  the  baghouses   were
designed  with an air-to-cloth  rati-o  of 5.9-6.7 to  I  (ACFM  to   sq.  ft.  of
cloth),  using  Dacron  HCE  filter  bags.   The baghouses  are  equipped   with
adjustable  pulse  durations   and cycle  times  for  compressed  air discharge
through rotary  airlock  valves.   When  in multiples,  the baghouses are mani-
folded to a  common  self-cleaning inlet, allowing part of any baghouse system
to  be  shut down for  repairs  without  taking  the  entire  baghouse  out  of
service.

      In the shale pyrolysis  process, hot,  sticky shale  dust is generated  at
three points:  the  raw shale preheater, the ball circulation system, and the
processed shale  wetter.  For  these point sources, venturi wet scrubbers were
evaluated due  to their high particulate  removal  efficiency  and the  wet,
sticky properties of the dust.  Again, the  information reported by Colony was
used  as  the  basis  for  the design  and cost estimates.   The  high energy
scrubbers used  for   the  shale preheater require  a  larger  pressure drop   than
conventional scrubbers.                                     .        .   •

     Fugitive dust is  generated  from mining and  blasting,  raw and processed
shale conveying,  conveyor transfer points,  baghouse dust discharge points  to
conveyor  systems, truck loading and  unloading,  and  disposal  operations.
These fugitive sources of particulates are controlled by water arid foam spray
suppression.   This system is  inexpensive and offers low water consumption arid
high removal efficiency.

     In addition  to  the major particulate sources mentioned above, there are
several  minor point sources,  such as the furnace and boiler stacks, for which
no controls  are applied.   .
                                     173

-------
     Table 5.1-2  lists  the design  parameters for each  of  the baghouses and
venturi wet scrubbers examined.  The capital, operating, and annual costs for
the   particulate   control   equipment   are   presented   in   Table 5.1-3.
Figures 5.1-2 and 5.1-3 present the cost curves for the baghouses and venturi
wet scrubbers, respectively.

     Total Particulate Emissions—

     The controlled particulates  from the point as well  as fugitive sources
are  summarized in  Table 5.1-4,  along  with  the  type of  control  technology
examined  for  each source.  The uncontrolled emissions  are also included in
the table to  give total  particulate emissions from the commercial operation.
Estimates for these emissions were taken from Colony's PSD permit application
(Colony Development Operation, 1977).

5.1.,2  Sulfur Control

     Processing of sulfur-containing fossil fuels will result in emissions of
sulfur  compounds, such  as H2S,  COS,  CS2,   RSH,  etc.,  or  their combustion
product, S02.   Federal  and State standards limit sulfur emissions because of
their  potentially hazardous  effects on  human  health  and  the environment.

     Inventory of Control Technologies—

     Two general  categories of technologies are available for the control of
sulfur  emissions:  (1) removal  of  sulfur  compounds  from flue, gases  after
combustion  (sulfur   dioxide   removal,   or  flue  gas  desulfurtzation)  and
(2) removal  of sulfur  compounds  from  gases  prior  to  combustion (hydrogen
sulfide removal).  Several  technologies in both categories offer recovery of
sulfur  in a  useful  form,  while others chemically fix the sulfur compounds on
a reagent which then requires disposal.

     Sulfur dioxide control (flue gas desulfurization).   Removal  of  sulfur
compounds from  flue  gases—that is, flue gas desulfurization (FGD)--is based
on  the  physical  and  chemical  properties of  S02  because  fuel-based sulfur is
usually converted to S02  upon combustion.   Flue gas  desulfurization can be
divided into two  categories:

     *    Wet scrubbing     i                                     :

     •    Dry scrubbing.
                                                                 !
     Wet  scrubbing  utilizes  a  solution or a slurry to  absorb the S02.   Dry
scrubbing uses either a dry reagent bed or an atomized solution of an aqueous
reagent  at  a  high  temperature to  remove the S02.   Both  categories  can be
divided  into  regenerable and  nonregenerable  processes.   The different types
of  S02  removal  processes  are shown  in  Figure 5.1-4,  and Table 5.1-5 gives a
brief description of each process.

     Wet scrubbing—The regenerable  wet scrubbing processes generally employ
a clean  alkaline  solution  to absorb  S02  in  a scrubber.   The resulting spent
solution  is  treated with  an  insoluble alkali makeup  which precipitates the


                                     174

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          TABLE 5,1-4.  TOTAL PARTICULATE EMISSIONS FROM THE PLANT

Stream
Number Emission Source
2
3
4
5
6
7
10
18
19
20
91
.104
118
119
125
138
179
Portal Transfer Point
Primary Crusher
Reclaim Tunnel
Transfer Tower Feed Bin
Fine Crusher
Fine Ore Storage
Mine Vent
Raw Shale Preheat System
Ball Circulation System
Processed Shale
Moisturizer
Hydrogen Furnace
Coker Feed Heater
Gas Oil Heater
Gas Oil Reboiler
Naphtha Heater
Diesel Equipment
Utility Boiler
8, 139 Conveyor Transfer Points,
Open Stockpiles, etc.
TOTAL
Parti cul ate
Control Description Emissions (lb/hr)
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
Baghouse
. —
Venturi Wet Scrubber
(high energy) .
Venturi Wet Scrubber
Venturi Wet Scrubber
—
— ,
-- ' '
-- . . •
: — '
Catalytic Converters
—
Water and Foam Sprays
,0.5
7.2
5.6
5.0
32.9
4.2
•• 25.0
81.0
37.8
38.3
; 11.4
1.1 •
0.4
' 1-6
0.2
: 19.0*
2.9
29.8*
303.8
Source:   Colony Development Operation, 1977, except those quantities noted
         with an asterisk (*) were estimated by SWEC.
                                     179

-------
                                   REGENERABLE
                                    PROCESSES
                                   NON REGENERABLE
                                      PROCESSES
                                   REGENERABLE
                                     PROCESSES
• WELLMAN-LORD
• MAGNESIUM OXIDE
- ABSORPTION/STEAM
  STRIPPING RESOX SYSTEM
• LIMESTONE
•LIME
-DOUBLE ALKALI
• SODIUM CARBONATE
-OOWA ALUMINUM SULFATE
- OIL SHALEf PROCESSED
  SHALE, NAHCOLITE)
-CHIYODA THOROUGHBRED  12!

•AQUEOUS CARBONATE


NONREGENERABLE
PROCESSES




                                                     — LIME
                                                        SODIUM CARBONATE
                                                     L—OIL SHAL£( PROCESSED
                                                         SHALE, NAHCOLITE)
SOURCE: SWEC
            FIGURE 5.1-4 SULFUR DIOXIDE CONTROL TECHNOLOGIES
                                     180

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absorbed  SQ2.   The  insoluble  alkali sulfite  and sulfate  crystals  are then
separated  from  the regenerated solution in a clarifier and possibly a  second
dewatering  step  such as a centrifuge.  The spent alkali sludge is treated by
calcining,  evaporation,  stripping,  etc.,  which drive off  the S02.   The S02
can  then  be converted  to a  useful  form of sulfur  such  as sulfuric acid or
elemental sulfur.

     In the nonregenerable  processes, this spent alkali  sludge  is sent to a
disposal area for  land filling.

     Dry scrubbing—The dry  scrubbing processes use a concentrated slurry of
alkaline crystals which are atomized  and injected into the flue gas stream as
it passes through a spray dryer.  The scrubbing slurry absorbs the S02  and is
dried by the hot flue gases.  The dried spent alkali is then removed from the
flue gas by an electrostatic precipitator or a baghouse.

     In the regenerable  processes,  the spent alkali is  reduced  to a sulfide
and  then  reacted with CQ2 to  regenerate the  alkali  and evolve H2S gas.  The
regenerated  alkali  is   recycled,  while  the  H2S  gas. may  be converted  to
elemental sulfur in a sulfur recovery unit.

     In  the  nonregenerable  processes,  the  spent  material   is.  sent  to  a
disposal  area  for landfill ing.   The spent material also may  be  recycled to
increase alkali utilization.

     Hydrogen sulfide control.   H2S   removal  can be divided  into  two  cate-
gories:

     •    Direct conversion                                 '     :.
     *    Indirect conversion.

     Direct  conversion  actually  oxidizes  H2S  to  elemental  S.   Indirect
conversion  involves removing acid gases (H2S and C02) from the gas stream and
requires  downstream  direct  conversion  or  further  processing to  treat  the
sulfur compounds.  Figure 5,1-5 lists the  H2S removal  systems available,  and
Table 5.1-6 presents a brief description of the process technologies.

     Direct conversion—As  shown in  Table 5.1-6, several  direct conversion
technologies  are  currently  available,  including  Glaus,   IFP,   Stretford,
Beavon, Giammarcd-Vetrocoke,  Takahax, Ferrox and Haines.   The conversion of
H2S to elemental sulfur takes place in the liquid-phase in all the processes,
except the Glaus and Haines which are .dry gas-phase removal  processes.

     Liquid-phase  direct conversion  processes  are  ideal  for treatment  of
gases containing low concentrations of H2S.  In these processes,  the acid gas
components  are absorbed  by  alkali solutions and then oxidized with dissolved
oxygen to  elemental  sulfur.   High  circulation rates of  the  alkali  solution
are  required  for  high  performance  and to  reduce thiosulfate' precipitate
formation.  High selectivity  for H2S removal  can also be  achieved by  taking
advantage of the higher H2S versus C02 absorption rates.
                                     185

-------
                   LIQUID-PHASED	
                    SOLVENTS
                                                              -CLAUS
                                                              •IFP
                                                              -STRETFORD  ,
                                                              •8EAVON
                                                              • GIAMMARCO-VETROCOKE
                                                              • TAKAHAX    ;
                                                              •FERROX     ;
                                                              • HAINES     :

                                                              -MEA
                                                              -OEA
                                                              • MOEA       ;
                                                              •AOIP/OIPA
                                                              -DGA(ECONAMINE)
                                                              -SNPA/DEA
                                                              -SCOT

                                                              -BENFIELD
                                                              -CATACARB
                                                              -GIAMMARCO-VETROCOKE
                                                              -ALKACIO(ALKAZiO)
   [—DIAMOX
	1-CARL STILL. ;
   I— COLLIN     !

   — SELEXOL
   — FLUOR SOLVENT
   —PURISOL
    -SULFINOL
   — AM1SOL
   -RECTISOL
                                                             c
SOURCE= SWEC
      MOLECULAR SIEVE
      CARBON BED

      IRON OXIOE(SPONGE)
      KATASULF
               FIGURE 5.1-5  HYDROGEN  SULFIDE  CONTROL TECHNOLOGIES
                                       186

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Operating Principle

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i Vacuum distillation
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Disadvantages







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-------
     The gas-phase direct conversion  (Glaus  and  Haines  processes)  consists  of
thermal  oxidation of  one-third of the  H2S to  S02,  followed by; a series  of
catalytic  reactors  that  react 'S02 with  the remaining  H2S to form elemental
sulfur.  The  heat for combustion  in  the  furnace is obtained  from the  oxida-
tion ,of H2S;  thus,  the H2S  concentration must  be high  enough  to sustain
spontaneous combustion.  Therefore, the gas-phase conversion  requires an  acid
gas  stream  with  a higher H2S  concentration  than the  liquid-phase  conversion.

     Indirect conversion—There  are  essentially five classes, of commercially
available,  indirect  H2S  removal  technologies  that are  used- in  conjunction
with direct conversion technologies;  these are,  removal of  H2S by:

       I. AlkanoTamine     .

      II. Alkaline salts                                            "    '    .

     III. Aqueous ammonia
      IV, Physical solvents

       V. Dry bed processes.

     The alkanolamine processes  (I) remove acidic impurities,  i.e., H2S,  C02,
COS-, and CS2, from  gases  by an acid-base chemical  reaction  with the  amine.
The process involves an absorption-regeneration  cycle of a  circulating  amine.
Commonly used amines are monoethanolamine (MEA), methyldiethanolamine (MDEA),
diethanolamine  (DEA),  diisopropanolamine  (DIPA)   and  diglycolamine   (DGA).
Major equipment systems  used in the  amine  process  are  a gas-amine contactor
(absorber)  for absorption  of the  acid gases and a regenerator (stripper) for
releasing the acid  gas from solution.  A downstream sulfur recovery facility
is required to oxidize, or recover, the H2S.                     '

     Alkaline  salt  processes  (II) use  an  aqueous  solution  of  a  buffered
potassium salt.   The  weak alkaline solution absorbs  the  acid gas components
of the  feed gas.  The process operates at  medium  to high pressures because
the absorption capability is influenced by the acid gas (H2S and C02) partial
pressures.    The  alkaline  solution  is  regenerated  by   reducing the  rich
solution pressure to  near ambient pressure, followed by  steam stripping and
sulfur recovery.
                                                                 '••' '
     The ammonia process (III) uses the same mechanism  for H2S removal  as the
alkaline salt process  (II)  except  the  ammonia is  used  as  the  absorption
agent.   Regeneration and additional sulfur recovery are necessary.

     Physical  solvents  (IV)  have  low heats of  solution  and  can  absorb  acid
gases in proportion to their partial pressures.  These  processes require  high
acid gas partial  pressures which  are achieved at  low gas pressures and  high
acid gas concentrations,  or at high gas pressures and low acid gas concentra-
tions.   Physical  solvent  processes are most economical when  the  feed  gas is
at high pressure  and  bulk removal of the acid components is desired.    A  high
degree of selectivity of H2S  absorption is possible, but additional equipment
is  required,   increasing  costs.   A  downstream  sulfur  facility  is   also
necessary to recover the H2S.
                                     192

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      Dry  bed  processes  (V)  generally  employ two  techniques  to  remove H2S from
 a  gas stream:  (1)  adsorption  onto a dry  bed,  such  as a .molecular  sieve  or
 activated carbon,  followed by desorption  of the H2S  from the  bed  using a hot
 gas  stream;  and  (2) reacting the  H2S with  a dry  bed material such as  iron
 oxide to form  a  solid  sulfide  compound,  which  is then oxidized by  air  to
 regenerate  the  dry bed  and  to form  elemental  sulfur.

      Sulfur Control  Technologies Analyzed—

      The  prime  sources  of S02 emissions  from the TOSCO II plant are  the fuels
 consumed  in  various unit  processes   and  auxiliary facilities. '  All of  the
 gaseous  fuels  except the  C3  fraction  (Colony  had   planned  to market  this
 liquefied  petroleum  gas,  or  LPG)  are  used in the   plant.   In: addition,  a
 portion  of  the  crude gas oil product (before upgrading) is combusted  in the
 ball  heater,  thermal  oxidizer and steam  superheater.

      According  to  Colony's  PSD  permit application  (Colony  Development  Opera-
 tion,  1977),  the TOSCO II  preheat  system  is capable  of removing  95%  of  the
 S02  from the ball  heater  and  thermal   oxidizer  flue  gases.   Furthermore,
 the  amount  of  S02  in  the  steam  superheater flue  gas  is  fairly  small.   If
 these  conditions  exist  in a commercial  operation,  then  there would  appear  to
 be  little  need  for removing the fuel-based sulfur  from the gas oil  in  order
 to  reduce the  S02  emissions.   From  the processing  viewpoint,  however,  the
 sulfur is removed from  the net oil products  by hydrotreating, but  this  is  not
 considered  a  pollution  control measure for  costing  purposes in  this  document.

     The  sulfurous  gaseous  streams  from  the  retort,  foul  water  stripper,
 ammonia  recovery  unit,  hydrotreaters,  and  delayed   coker are treated  for
 sulfur removal.   The most significant compound  of  sulfur in these streams  is
 H2S  (although COS,  CS2, and mercaptans  also have been reported),;  therefore,
 the  technologies  examined  are  based on  removing  and  recovering  the  H2S..
 Since  the  H2S  is recoverable  as  salable  elemental   sulfur (as  proposed  by
 Colony),  flue gas desulfurization technologies  were  not analyzed  in detail.

     Two  separate H2S removal  and recovery  processes, based  on the  informa-
 tion  provided by  Colony (Colony Development  Operation,  1974  and 1977),  have
 been examined in this manual.  These systems are:

     •    DEA/Claus/Wellman-Lord
     •    Stretford.


     Both of  these  systems  have been used  in oil shale related industries  at
 a scale  necessary for  the  TOSCO II  plant.   The individual  technologies  in
 these  systems  have  been  proven  to be  technologically  and  economically
 feasible, and substantial cost  and  design criteria are available  in  the open
 literature and from the technology vendors.

     The  amine  process  (alkanolamine  process  I)  proposed   by  Colony   to
desulfurize the retort  gas  is  the DEA (diethanolamine)  process..  It removes
approximately 99% of the ,C02 and all  but 135 ppmv of  the H2S from the retort
gas  (Colony Development Operation,  1977).  The acidic  gases in the retort gas


                                     193

-------
are absorbed in the DEA solution, and the rich amine stream is regenerated in
a steam  stripper  column and returned to the absorption column.  The stripped
acid  gases  (primarily  H2S  and C02)  are  treated in a  Claus  unit for sulfur
recovery.   This  high removal  of C02  is  not required  for LPG ;and  fuel gas
production  and  it increases operating costs because of the large quantities
of steam  needed  in the stripping (regenerating)  section  of the.process.  An
alternate amine system  using MDEA (methyldiethanolamine)  is highly selective
for H2S  removal.   This  selectivity allows a reduction  in steam;requirements
of approximately  20%  as compared to DEA and, consequently, reduces operating
costs.                                                     .

     The stripped acid gas  stream leaving the amine unit  is approximately 14%
H2S by weight.  This stream and overhead gases from the ammonia recovery unit
and foul water stripper are treated in the Claus process.

     In the Claus process,  the acid gas  is  blown into a  sulfur burner where
it  is mixed  with  sufficient  air to  oxidize  one-third  of the H2S  to  S02.
Portions  of the  other organic  sulfur compounds  are  also converted  to S02
during  combustion.   The S02  and remaining H2S enter a reaction  furnace and
then  pass  through  a  three-stage catalytic  reactor  where  they 'react at 95%
efficiency  to  form  elemental  sulfur.   A higher  conversion  efficiency  is
attainable  with additional  catalytic  stages.   The unreacted  S02  and  H2S are
sent to a Wellman-Lord tail gas unit.

     In the Wellman-Lord unit, the non-S02 sulfur compounds in the Claus tail
gas are  converted  to  S02  by  incineration.   A majority  of the: S02  is  then
absorbed in Na2S03  solution, while the remainder is vented to the atmosphere.
The S02-rich  solution  is  regenerated by steam stripping and the desorbed S02
is recycled back  to the Claus unit for  further  recovery.  An S02 absorption
efficiency  of 92% is  assumed for the process,  but higher efficiencies may be
obtained by increasing  the  contact time between the reactants.  Both the 95%
efficiency  for  the Claus   process  and 92%  efficiency for  the We11man-Lord
process  have  been specified by Colony (Colony Development Operation, 1977).
                                            1       •  • •
     The  other  H2S removal  system examined  is the Holmes-Stretford process,
which has the capability of treating gas streams with low H2S concentrations.
The  Stretford  process  is  a  liquid-phase  direct  conversion system  which
selectively  removes  the  H2S  and  catalytically  converts  it to  elemental
sulfur.  The process is capable of reducing the H2S in the treated gas stream
to 30 ppmv.  Appreciable amounts  of carbon dioxide and other non-H2S sulfur
compounds are not removed by the Stretford process.

     Tables 5.1-7 through 5.1-9  give  the major' equipment  lists  for  the  DEA,
Claus,  and  Wellman-Lord  processes,  respectively.   The  major, capital  and
operating   cost   items   for  the  Stretford  technology   are  presented  in
Table 5.1-10.  The cost of sulfur control  in the TOSCO II plant, using either
the DEA/Claus/Wellman-Lord  processes  or the Stretford  process, /is presented
in Table  5.1-11.   Figures  5.1-6 through  5.1-9  provide cost  curves  that are
specific  to  the  design ' of  the  DEA, Claus,  Wellman-Lord,  and  Stretford
processes examined  in this  manual.   Process descriptions and stream composi-
tions for these technologies are presented in Sections 3 and 4.
                                     194

-------
           TABLE 5.1-7.   MAJOR ITEMS IN THE DEA GAS TREATING PROCESS*
 Capital  Cost Items
Operating Cost Items
 Absorbers (5)
      4'  diameter x 70'

 Regenerators (4)
      12'  diameter x 70'

 Flash Tanks  (8)
      7'  diameter x 21'.

 Surge Tanks  (8)
      7'  diameter x 35'

 Reflux Tanks (8)
      3'6" diameter x 14'

 Lean  Amine Pumps (8)
      1,619 gpm @ 200 HP

 Still  Reflux Pumps (8)
      135  gpm § 10 HP

 Lean  DEA/Rich DEA Heat Exchangers  (4)
      66 x 10s Btu/hr

 Still  Reboiler Heat Exchangers  (4)
      106  x 106 Btu/hr

 Amine Reclaimers (4)
      10.6 x  10s  Btu/hr

 Still  Condenser  Aerial Coolers  (4)
      66 x io6 Btu/hr

 Lean  OEA  Aerial  Coolers  (4)
      29 MMBtu/hr with a  558-HP  Motor

 Site  Preparation and Foundations

 Piping

 Electrical

 Instrumentation  and Controls

 Painting
Diethanolamine (DEA) Makeup
     65 gpd

150 psig Steam
     330,750 Ib/hr

Process Water                 .
     368 gpd

Electricity                  :
     2,930 kW

Manpower
     h Operator per Shift    :
     h Supervisor on the Day Shift Only
.* Design basis:  6,700 ACFM.

Source:  SWEC estimates based  on  information  from  Maddox,  April  1977.
                                      195

-------
               TABLE 5.1-8.  MAJOR ITEMS IN THE CLAUS PROCESS*
Capital Cost Items                          Operating Cost Items

Reaction Furnace                            Boiler Feedwater
                                                 43 gpm
Combustion Air Blower
                                            Electricity
Waste Heat Boiler                                825 kW

Catalytic Reactors (3)

Sulfur Condensers (4)

Reactor Preheaters (2)                                           '     >

Sulfur Rundown Tank

Knock-out Vessel

Piping

Electrical'

Instrumentation and Controls                     •

Site Preparation and Foundations

Painting                                                         ,


* Design basis:  14,500 ACFM, 173 LTPSD sulfur recovered.

Source:  SWEC estimates based on information provided by Pritchard Corp.,
         September 14, 1981.                                 •    .
                                     196

-------
           TABLE 5.1-9.  MAJOR ITEMS IN THE WELLMAN-LORD PROCESS*
Capital Cost Items
Operating Cost Items
Stack
     8' diameter x 210'

Package Boiler
     50 x 106 Btu/hr

Spray Tower
     16' diameter x 20'

Spray Tower Condenser
     2,600 ft2

Spray Tower Recycle Pumps (2)
   •  2,220 gpm @ 50 HP

Liquid Vapor Separator
     11' diameter x 17'

Absorber  '
     14' diameter x 40'

Absorber Recycle Pumps (4)
     61 gpm @ 1 HP (2)
     47 gpm @ 1 HP (2)

Surge Tank
     14,000 gal

Surge Tank Pumps (2)
     19 gpm @ 1 HP

Evaporators-Crystal! izer
     4' diameter x 12'

Evaporator-Crystal!izer Recycle
  Pumps (2)
     12 gpm @ 1 HP

Evaporator Heat Exchanger
     200 ft2

Evaporator Condenser
     400 ft2
Na2COs Makeup
     1,728 Ib/day

Antioxidant
     29 Ib/day

150 psig Steam
     19,170 Ib/hr

Cooling Water
     5,760 gpm

Makeup Water
     2 gpm
Fuel
     83 x 106 Btu/hr
Electricity
     56 kW

Manpower
     1 Man/day
                                                         (Continued)
                                     197

-------
                            TABLE  5.1-9   (cont.)
Capital Cost Items                          Operating  Cost  Items

Evaporator Liquid-Vapor Separator
     1" diameter x 4'

Dissolving Tank
     14,250 gal

Feed Pumps (2)
     30 gpm @ 1 HP

Storage Tank
     6,400 gal

Absorber Heat Exchanger
     630 ft2                                   .                  ,

Weighing Belt                                                    j
                                                                 !
Piping                                                           :

Electrical                                                       '

Instrumentation and Controls                       .             "j     '

Site Preparation and Foundations                                 i

Painting                            •                         '    ,
    .   "             ........         '                          i

* Design basis:  25,000 ACFM, 173 LTPSD sulfur recovered in the Qlaus plant.

Source:  SWEC estimates based on information from U.S. EPA, January 1975.
                                     198

-------
          TABLE 5.1-10.  MAJOR  ITEMS  IN THE HOLMES-STRETFQRD  PROCESS*
Capital Cost Items
Operating Cost Items
Knock-Out Drum
     10' diameter x 22'

Absorber
     18' diameter x 75'

Oxidizers (7)
     37' diameter x 62'

Pump Tanks (4)
     37' diameter x 50'

Circulation Pumps (5)
     20,000 gpm

Flash Drums (2)
     20' diameter x 50'

Slurry Tanks (2)
     35' diameter x 50'

Slurry Pumps (4)
     430 gpm

Filter Systems (5)
     8,500 Ib/hr

Sulfur Melters (4)
     4 x IO6 8tu/hr

Sulfur Decanters (4)
     5'  diameter x 171

Sulfur Storage Pits (2)
     4 x 10s Ib

(Evaporators (2)
     6,000 gpm

Heater/Coolers (4)
     Heating Duty = 10 x io6 Btu/hr
     Cooling Duty =  5 x io6 Btu/hr

Plot Area
     49,000 ft?
Holmes-Stretford Mix
     760 Ib/day

Soda Ash
     15,222 Ib/day

Process Water
     65 gpm

Steam
     4,500 Ib/hr

Cooling Water
     225 gpm

Electricity
     18,600 kW

Manpower
     2 Men/day
* Design basis:  6,700 ACFM, 173 LTPSD sulfur recovered.

Source:  SWEC estimates based on information from Peabody Process Systems,
         Inc., February 1981.
                                      199

-------





























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     Other  Sulfur  Control Technologies Analyzed—

     In  addition  to  the DEA/Claus/Wellman-Lord processes  and the  Stretford
process,  the  Shell  Glaus   Off-gas  Treating  (SCOT)  and  methyldiethylamine
(MDEA) processes were  analyzed.  These technologies  have  not  been  proposed  by
Colony, but they may be  applicable to the TOSCO  II retort gas.   ,

     The  SCOT  process  can  be  used as  an alternate for  the Wellman-Lord
technology, while  the MDEA process  can  be  used as  a  replacement  for  the DEA
and We11man-Lord (or SCOT) technologies.                         ;

     The  SCOT  technology has been developed specifically for the Claus tail
gas  cleanup.   The  sulfur  species in  the feed  stream to  the  SCOT  unit are
first  converted to S02  by  incineration, then to H2S  over  a catalyst in the
presence  of a reducing gas.  The resulting gas is cooled  in a quench tower  to
knock  out  moisture,   and  the  H2S  is  subsequently  absorbed  in diisopropan-
olamine   (OIPA).   The  clean  gas  is  incinerated   and  then  vented  to  the
atmosphere,  while  the rich amine   is  regenerated  by  steam  stripping.   The
H2S-containing  overhead  vapors  from the DIPA regenerator are recycled to the
Claus unit  for  further recovery of sulfur.  A removal  efficiencyjto  ^300 ppmv
H2S  in  the  fuel   gas is  obtainable  with  the SCOT  technology.    The  DIPA-
solution  absorbs  approximately 25%  of  the C02  and  recycles  it :to  the Claus
unit.  Figure 5.1-10 presents the flow scheme for the  SCOT  process.

     The  material  balances  for  the  Claus  and  SCOT processes,  when  applied
specifically  to   the  acid  gas  from  the  TOSCO II  plant,  are   given   in
Tables 5.1-12 and  5.1-13.   The treated fuel gas  is  used as  the reducing gas
(a substoichiometric  amount  of air  is used in the line heater to oxidize the
fuel gas  to CO  and H2 which then react with S02 to  produce H2S and  C02).   To
avoid  the H2S  odor  problem, the SCOT  flue gas is  incinerated before it  rs
vented to the  atmosphere.   Table 5.1-14 contains the  equipment breakdown,  as
well as  capital  and operating costs, for the SCOT process.   A cost  curve for
the process is presented in Figure 5.1-11.

     The  MDEA process  is selective in removing H2S from a gaseous stream when
appreciable  quantities  of   C02  are present.    The  DEA  process  scrubs  out
practically all  of the C02  at 30 ppmv H2S  level in the  treated gas.  On the
other hand, the MDEA process at the same H2S removal  efficiency ; absorbs only
30-40% of the  C02.  This selectivity results in a significantly lower steam
requirement for. the MDEA  regenerator.   In addition,  the acid  gas  stream  is
smaller  in  volume, resulting  in  a  reduction  in the  size  of the downstream
treatment equipment.   The  acid gas is  also  higher  in H2S concentration;
therefore,  it is more  suited as a feed to the Claus  process.

     A  process  flow   scheme   for  the  MDEA  technology  is  presented   in
Figure 5.1-12.   The  operation  of this  process  is similar  to the  DEA  or any
other amine process.  The acidic gaseous components  such  as H2S and  C02 react
with the  amine  to  form rather stable sulfide or carbonate salts; thus, they
are retained by the amine.   Other gaseous components  pass  through  the amine
unreacted.  The  rich  amine  solution  is then regenerated  by steam stripping,
where the salts are  decomposed  back to  the amine  and the acid gases.   The
lean amine  is recycled, while the acid gases can be  treated further.

                                     205

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-------
                TABLE -5'. 1-14.  MAJOR  ITEMS  IN  THE  SCOT PROCESS*
Capital Cost  Items
Operating Cost Items
Feed Heater

Fixed Bed Reactor

Waste Heat Boiler

Cooling Tower

Cooling Tower Pumps (2)

Cooling Tower Condenser

Amine Absorber

Amine Pumps (2)

Absorber Cooler

Stripper

Absorber/Stripper Heat Exchanger

Stripper Condenser

Reflux Drum

Reflux Pumps (2)

Stripper Reboiler

Lean Solution Pumps (2)

Piping               .  ,.-

Electrical                      .

Instrumentation and Controls

Site Preparation and Foundations

Painting

Fixed Capital  Cost, $103    8,295
DIPA Makeup
     4 gpd

Fuel Gas  -.-                 '  .
     1,970."CFM

Cooling Water
     5,500 gpm

Electricity
     1,650 kW               ;

Manpower
     % Man/day

Direct Annual Operating Cost, $1Q3
     Maintenance           214
     Operating Supplies      7
     Labor                  39
     Electricity         1,375

       TOTAL             1,635
* Design basis:  25,000 ACFM, 173 LTPSD sulfur recovered in the Glaus plant.

Source:  SWEC estimates based on information provided by Pritchard Corp.,
         September 14, 1981.                                       :  .  -
                                      209

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     The  MDEA process  can  also be used in  the  Glaus tail gas cleanup.   Its
operation  would  be similar to  the  SCOT process, except the  DIPA solution in
the. SCOT process would  be replaced  w.ith the  MDEA solution.

     Table 5.1-15  gives  the composition of the TOSCO  II  retort  gas before  and
after   MDEA   treatment.    The  C3/C4   gases   may   be   similarly   treated.
Table 5.1-16  presents  the capital  and  operating cost components of  the MDEA
process  as an acid  gas  removal  technology as  well  as  a tail  gas  treatment
technology.   Specific  cost  curves  for  the  two  applications are presented in
Figure 5.1-13.


    TABLE 5,1-15.  RETORT GAS COMPOSITION BEFORE AND  AFTER  MDEA TREATMENT

Component
H2S
RSH
cos
H2
CO
C02
CH4
C2H4
C2Hg
C3H6
CsH.8
H20
TOTAL
MWt.
MWt
34
56
60
2
28
44
16
28
30
42
44
18

. Untreated
Gas
Ib/hr
12,197
14.5
120
3,590
8,380
79,070
52,510
34,383
19,958
1,324
652
932
213,130.5

Treated Gas
Mass
0.005
0.008
0.03
2.03
4.73
31.26
29.65
19.42
11.27
0.75
0.37
0.48
100.00
20.
Mole
0.003
0.003
0.01
20.82
3.47
14.59
38. 06
14.24
7.72
0,37
0.17
0.54
100.00
54
Mass Flow,
Ib/hr
8.8*
14.5
60
3,590
8,380
55,350
52,510
34,383
19,958
1,324
652
843
177,073.3

Flow,
Ib-moles/.hr
0.26
0.26
'• ' 1.0
: 1,795.0
; 299.3
^ 1,258.0
3,281.9
1,228.0
665.3
31.52
14.82
46.83
8,622.2

Total
Total
Total
Total
H
0
C
S
14,
25.
59.
o.
64
45
41
03
25
45
105

,930.
,059.
,192.
47.
6
1
9
8

* Assuming the after treatment concentration of 30 ppmv H2S.

Source:   DRI estimates based on information provided by SWEC.
                                     212

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                                  TABLE 5.1-16.  MAJOR ITEMS  IN THE MDEA PROCESS
Acid Gas Removal3
Capital Cost Items
Absorbers (2)
1-7' diameter x 52'
L-3' diameter x 36'

Stripper
3' diameter x 30' ,

Flash Tank '
4,000 gal

Surge Tank
11,000 gal

Ami ne/ Aim'ne Heat Exchanger
24,700 ft2

Still Condenser
17,110 ft2
285-HP fan

Lean Amine Cooler
31,350 ft2
830-HP fan
Still Reboiler
24,810 ft2

Amine Reclaimer
2,480 ft2

Reflux Tank
2,150 gal

MDEA Pump
2,500 gpm @ 310 HP

Still Reflux Pump
10 HP
,
Piping

Electr-ical '
Operating Cost Items
MDEA Makeup
50 Ib/hr

150 psig Steam
22,140 Ib/hr

Electricity
1,075 kW

Manpower
2 Men/day

Direct Annual
Operating Cost, $103
Maintenance 480
Operating
Supplies 17
Labor 138
Steam 591
Electricity 255
TOTAL 1,481




















Tail Gas Treatment
Capital. Cost Items
Absorber
9' diameter x 40'

Stripper
11.5' diameter x 50'

Flash Tanks (2)
6' diameter x is1

Surge Tanks. (2)
6.' diameter x 30'

Reflux Tank
2' diameter x 8'

MOEA Pump
1,360 gpm @ 125 HP

Reflux Pump
1,400 gpm @ 9 HP

Amine/Amine Heat Exchanger
16,000 ft2
Lean Amine Cooler
20,000 ft2
530-HP fan

Still Condenser
10,900 ft2
182- HP fan

. Still Reboiler
15,800 ft2

. Amine Reclaimer
1,600 ft2

Piping

Electrical

Operating Cost .Items
MOEA Makeup
0.7 Ib/hr

150 p'sig Steam
8,370 Ib/hr

Electricity
;3,190 kW

Manpower
2 Men/day

Direct Annual Operating
Cost, $103
Maintenance 244
Operating
i Supplies • 7
Labor 138
Steam 284
Electricity 149
TOTAL 822
,

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, ' .
Instrumentation and
  Controls
Site Preparation and
  Foundations
Painting
Fixed Capital Cost, $103
19,000
  Design basis:   2,500 gpm MDEA circulated.
  Design basis:   1,360 gpra-MDEA circulated.
  Source:   SWEC.
                                Instrumentation and
                                  Controls
                                Site Preparation and
                                  Foundations
                                Painting
                                Fixed Capital Cost, $103
9,420
                                                       213

-------
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      Total Sulfur Emisslons—•

      The four  major sources  of sulfur emissions  (as  S02)  from the TOSCO II
 plant are:                                                       .;

      •    Ball heater/thermal  oxidizer                            ...  -
      •    Ball circulation system stack                           .

      *•    Tail gas from the Wellman-Lord unit

      •    Process heaters/furnaces and utility boilers.

      The ball heater burns  the treated fuel gas (135 ppmv H2S) and untreated
•shale oil,  while the thermal oxidizer uses the C4 liquids and untreated shale
 oil  as the  fuels.  The major source of S02 in these systems is the shale oil,
 as it contains  approximately  0.9% sulfur by weight.  The total S02 emissions
 from these sources  would  be in excess of 1,100 Ib/hr; however, Colony claims
 that about 95%  of  the  S02 is absorbed  on  the raw shale, thus only 5% of the
 S02  is emitted  to  the  atmosphere (Colony Development  Operation,  1977).   The
 ball  circulation system emits  the flue gas  from  the  steam superheater which
 also burns  the  crude  shale  oil.  The tail  gas  from the Wellman-Lord process
 contains approximately  105  "Ib/hr of  S02  (at a sulfur  removal  efficiency of
 92%}.   All  process,  heaters  and furnaces and  the  utility boilers  consume the
 treated fuel  gas; therefore, they emit insignificant amounts of S02, with the
 noted exception  of  the hydrogen  unit furnaces.   These furnaces  consume  a
 large quantity  of  the  fuel  gas, hence  emit a significant quantity  of S02.
 The   fuel  needs  for  various   heating  systems  have  been  'provided  in
 Tables 4.2-22 and   4.2-23.   The  total  S02  emissions  from  the  plant  are
 presented in  Table  5.1-17.

 5.1.3  Nitrogen  Oxides  Control

      In   oil  shale  processes,  nitrogen  enters the system  from;  two  primary
 sources:   (1) the fuels derived from the raw shale, and (2) the;air required
 for   combustion   in  the  various  furnaces,   heaters,   auxiliary  boilers  and
 incinerators.   A portion of this nitrogen is converted into other forms such
 as  nitrogen oxides  (NOx)  and  ammonia (NH3).  The  NOx  produced  during fossil
 fuel  combustion  are  emitted  as  NO and N02  in flue  gases.   These compounds are
 formed from the  oxidation of  nitrogen compounds (e.g., ammonia,  cyanides) in
 the  shale-derived  fuels  and/or from  the  fixation  of  atmospheric  nitrogen
 (N2).   A large portion  of ammonia resulting from  the  pyrolysis  of the  shale
 is  usually  removed  in  the gas  condensate,  or foul  water, when the retort gas
 is  cooled  or  scrubbed with water.   This  removal  and  subsequent  recovery of
 ammonia  provide  an  indirect control  over  NOx emissions.  Since the  recovery
 of ammonia  from  an aqueous solution  also constitutes water pollution control,
 this  aspect.  of   the NOx control  is discussed  under  water management  (Sec-
 tion  5.2).   The  portions  of  ammonia  and fuel-based  nitrogen  that are  riot
 removed   in  the  gas  condensate  may require  removal  or  control  prior  to
 emission  to  the  environment.    Federal  and Colorado   State  standards  and
 regulations limit  NOx  emissions  because  of their  potential  role  in  the
 formation of  photochemical smog  and  acid precipitation.
                                     215

-------
               TABLE 5.1-17.   TOTAL S02 EMISSIONS FROM THE PLANT
Stream
Number
18
19
57
91
104
118
119
125
138
179
TOTAL
S02 Emissions (Ib/hr)
Case: Studies
Emission Source
Raw Shale Preheat
System
Ball Circulation
System
Sulfur Plant
Hydrogen Furnace
Coker Feed Heater
Gas Oil Heater
Gas Oil Reboiler
Naphtha Heater
Diesel Equipment
Utility Boilers

Control Description
c

We 11 man- Lord
d
d
d
d
d
—
d

A,Ba ,
51.0
94.3
94.5
27.4 ;
2.8
0.9
3.8
0.4
20.0
7.2
302.3 •
Cb
44.7
94.3
—
23.9
2.4
0.8
3.3
0.3
20 . 0
6.3
196.0

  The S02 emissions have been taken from Colony's PSD permit application.

  The data are calculated.  The emission from the preheat system has been
  reduced by 95%, as claimed by Colony.

  Amine is the primary control for the process fuel.  Adsorption of S02 on
  the raw shale serves as the secondary control.                 i

  Amine Cor Stretford) is the primary control as the treated fuel gas  is
  used.              .          •

Source:   DRI estimates based on Colony Development Operation, 1977.
                                     216

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      Inventory  of Control  Technologies—            .

      There  are  three  categories  of  NOx  control  technologies:   '  \

      *    Reduction of  nitrogen  in  the  fuel

      *    Combustion  modifications  ,

      *    Stack gas removal.

      These  processes  are shown  in  Figure  5.1-14  and  are  discussed  briefly  in
Table 5.1-18.

      Reduction  of nitrogen  in  the fuel.  Burning  fuels  low  in  nitrogen  is the
simplest  method of controlling  NOx emissions  arising from fuel-based  nitro-
gen.   Hydrotreatment of fuel  oils and  water scrubbing of  fuel  gases are
fairly effective  in removing the fuel-based nitrogen.

      Combustion modifications. .  The generation of NOx  by thermal fixation  of
atmospheric  nitrogen  is dependent  upon the  flame temperature, concentration
of  nitrogen, time history  of  individual  combustion  gas  pockets,  and the
amount of excess air present.    To  some extent, these variables ;are control-
lable, and  the  production of NOx can be minimized for a particular  combustion
process.

      Combustion control  of NOx may be  accomplished  by  several methods.  One
approach  is design and operation   of burners  with  fuel-rich mixture ratios.
This  technique,  called  off-stoichiometric  combustion,  produces  low   flame
temperatures and,  hence, potentially Tow NOx formation.  A significant  excess
of oxygen is avoided in the combustion zone by diverting some portion  of the
inlet air through, remote locations  in the  burner or through entirely separate
secondary combustion  air ports.          .                        ,     •

     Another NOx  reduction technique, based on combustion modification,  takes
advantage of the  strong temperature dependency of nitric oxide (NO) formation
on peak combustion temperatures.  Reduced flame temperatures may be obtained
by  direct  reduction  of  gas  temperature  or  by  indirectly  increasing heat
transfer.    Direct techniques  include  recirculating product  flue  gases back
into the combustion zone where they serve  as diluents absorbing heat, thereby
reducing  maximum  flame  temperatures  achieved.   Other  direct  techniques are
reduced combustion air preheat and water/steam injection.   The latter is more
applicable to gas turbines.   Indirect NOx reduction  relating  to. the combus-
tion  process  usually  involves  furnace designs  with  increased burner spacing
and heat removal capability.  Flame temperature reduction does not reduce NOx
formation from fuel nitrogen but does reduce atmospheric N2 fixation.

     Stack gas removal.   Flue  gas  treatment  for NOx  removal  is  a relatively
new,  developing  technology.   Two  broad  categories  may  be defined:   wet
processes  in which  NOx  is  absorbed  into  an  aqueous  solution,  and dry
processes in which NOx is reduced by ammonia.

     The wet NOx removal processes  also serve as a mechanism to reduce sulfur
dioxide emissions and,  as such,  can provide effective  environmental  control

                                     217

-------
 NITROGEN OXIDES
    CONTROL
 TECHNOLOGIES
                             FUEL NITROGEN
                                REMOVAL
                              COMBUSTION
                              MODIFICATIONS
                               STACK GAS
                                REMOVAL
SOURCE'-  SWEC
     NH3
  SCRUBBING
                                                             TWO-STAGE
                                                             COMBUSTION
                                                             LOW ^-EXCESS
                                                                AIR
                                                             FLUE GAS
                                                           REC1RCULATION
                                                          UDWER TEMPERATURE
                                                          THROUGH FASTER
                                                          HEAT RELEASE
                                                             ACTIVATED
                                                              CARBON
                                                             ABSORPTION
  CATALYTIC
DECOMPOSITION
                                                             SELECTED
                                                            CATALYTIC
                                                            REDUCTION
                                                             THERMAL
                                                             DENOx
                                                           ELECTRON BEAM
                                                            SCRUBBING
                                                             ABSORPTION
                                                             REDUCTION
                                                             ABSORPTION
                                                             OXIDATION
                                                             OXIDATION
                                                            ABSORPTION
                                                             REDUCTION
         FIGURE 5.1-14   NITROGEN OXIDES CONTROL TECHNOLOGIES

                                   218

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               TABLE  5.1-19,   TOTAL  NOx  EMISSIONS  FROM THE  PLANT

Stream
Number
10
18 .
19
91
104
118
119
125
138
179
TOTAL
Emission Source
Mine Vent
Raw Shale Preheat System
Ball Circulation System
Hydrogen Furnace
Coker Feed Heater
Gas Oil Heater
Gas Oil Reboiler
Naphtha Heater
Diesel Equipment
Utility Boilers
NO>]C Emissions
:(lb/hr)
, 250.0
1,314.8
' . ". 113.4 .
: 82.2
; 8.4
2.7
; 11.2
1.3
' 267.9*
'• 21.6
2,073.5
Source:  Colony Development Operation, 1977, except the quantity :noted with
         an asterisk (*) was estimated by SWEC.
in  government  regulations  restricting  their emission.   Federal  and  State
regulations  limit  these hydrocarbon  emissions  because of  their  role in the
formation of photochemical  smog and ozone production.

     Inventory of Control Technologies—

     As  illustrated  in Figure 5.1-15  and  discussed  in  Table 5.1-20, hydro-
carbon emissions  can be controlled  by .the  following categories  of control
technologies:                                                    :     '       •

     •    Additional  sealing of process equipment

     •    Vapor recovery
     *    Complete fuel combustion

     •    Catalytic converters                                   ;

     •    Thermal  oxidizers.                     •
   -.                      ' ,    '               •       •             !

                                     222

-------
     HYDROCARBON
      CONTROL
     TECHNOLOGIES
                                  ADDITIONAL SEALING
                                     ON PROCESS
                                      EQUIPMENT
                                        VAPOR
                                      RECOVERY
COMPLETE FUEL
 COMBUSTION
                                     CATALYTIC
                                    CONVERTERS
                                       THERMAL
                                     OX10IZERS
SOURCE: SWEC
       FIGURE 5.1-15   HYDROCARBON CONTROL TECHNOLOGIES

                            223

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-------
     Additional  sealing  of  process  equipment.   Hydrocarbon  emission  control
by. additional  sealing of process and  storage equipment is best  accomplished
by  engineering these features into  the  plant.  This  includes  double seals  on
tanks,  pumps,  and other rotating  machinery, closed-loop  sampling, caps  on
open-ended  valves, and  periodic monitoring  of equipment to find  hydrocarbon
lea.ks  quickly./  This will  result in a minimum additional plant; capital  cost
and;  will  more than pay  for itself  due to  the  value of  the hydrocarbons which
are  prevented  from being emitted.

     Vapor  recovery.   When   hydrocarbon  vapor emissions cannot be  controlled
by  additional  sealing of equipment, a vapor  recovery system canibe installed
to  collect and  condense the vapors by  refrigeration and  return them to the
process.                                                         :

     Complete  fuel combustion.   The  most  cost-effective  way   to control
hydrocarbon  emissions  from  fuel   combustion  processes  is  to  operate  the
process  with  enough  excess air to  ensure complete  oxidation of  all hydro-
carbons to  C02 and H2Q,  i.e., complete fuel combustion.

     Catalytic converters.   When complete  fuel combustion does  not  occur, the
hot  exhaust gas  from the process can  be sent through  a catalytic  converter.
In  the  catalytic  converter,  the   gas  is  passed  over  a catalyst where  the
unburned  hydrocarbons  are reacted  with  the excess air  in the  exhaust gas and
are  converted to C02 and  H20.

     Thermal oxidizers.   Hydrocarbon  vapor  streams  or any other waste  gas
stream containing  unburned  hydrocarbons  can be burned  in  a thermal oxidizer
with excess air  and additional fuel,  if needed; this completely oxidizes all
hydrocarbons to C02 and  H20.

     Hydrocarbon Control  Technologies  Analyzed—                 '

     The hydrocarbon emissions in the  TOSCO II plant emanate from the leakage
in  the  valves,  pumps,  etc., as  the  fugitive emissions  from  oil product
storage, and due to the  incomplete combustion of the fuels.

     A thermal  oxidizer  system was  examined  for  controlling  the hydrocarbon
vapors generated in  the  lift pipes  in order to reduce the emissions from the
preheat  system.    The oxidizer  system  burns  additional  fuel  in  order to
incinerate  hydrocarbons  picked up  by the  hot flue gas during preheating of
the  fine,  raw  shale.    This  system  has   been proposed  by   Colony (Colony
Development Operation, 1977).

     Hydrocarbon emissions   from diesel-burning  equipment are  controlled by
installation  of catalytic   conversion  systems.   The  least costly fugitive
hydrocarbon emissions  control for  storage tanks  is  proper  sealing.  Alter-
natively,  vapor  recovery  can be  used, but  the  expense is  extremely  high
for  these systems.   As  a standard industry practice,  double-sealed, floating
roof storage tanks are provided for volatile product storage.   Internal plant
leaks are controlled  by  use of adequate seals  and strict maintenance proce-
dures.    The furnace  and boiler stacks  emit partially  burned hydrocarbons.
                                     225

-------
Except  for  using  proper combustion  practices,  no other  technologies  are
provided  for  controlling  hydrocarbons  from  the   fuel  combustion  sources.

     Table 5.1-21  lists the design parameters  for the thermal  oxidizer,  while
Table 5.1-22   lists  other   hydrocarbon   control   practices  arid   equipment
considered.  Table 5.1-23 presents  the costs  for hydrocarbon  control  for  the
entire  plant.   A  cost  curve  for  the  thermal  oxidizer  is  presented   in
Figure 5.1-16.                                                   ;


             TABLE  5.1-21.  MAJOR ITEMS IN THE THERMAL OXIDIZER*:
Capital Cost Items                                Operating  Cost  Items

Oxidizer with Brick Liner                       .  Fuel
pip1ng                                   •              610 x MMJtu/hr

Electrical                                        Maintenance'    •

Instrumentation and Controls

Supports
Painting
* Design basis:  2,080,200 ACFM.

Source:  SWEC.

                       1 '     ,   '     "       • '               " '     ','
         TABLE 5.1-22.  HYDROCARBON CONTROL PRACTICES AND EQUIPMENT


Capital Cost Items                                Operating Cost Items

Floating Roof Storage Tanks            .           Maintenance
  1-150' diameter x 40', 150,000 bbl
  2 - 140' diameter x 40', 219,000 bbl total
  Welded API 650 code
  Double seals
  Carbon steel

Complete Combustion of Fuels

Dual Mechanical Seals on  Pumps and Valves                        ;

Catalytic Converters on all Diesel Equipment                     !

Monitoring Equipment                                             ;


Source:  SWEC.

                                     226         .                :

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    ,  Total  Hydrocarbon  Emissions'—
      Table  5.1-24 summarizes  the hydrocarbon  emission  sources ! and  control
 equipment used  for the  emissions.
           TABLE  5.1-24.   TOTAL HYDROCARBON EMISSIONS  FROM THE  PLANT
 Stream
 Number
          Emission Source
Control Description
   Hydrocarbon
Emissions (Ib/hr)
 10       Mine Vent
 18       Raw Shale Preheat
            System
 19       Ball Circulation
            System
 91       Hydrogen Furnace
104       Coker Feed Heater
118       Gas Oil Heater
119       Gas Oil Reboiler
125       Naphtha Heater
138     .  Diesel Equipment.
179       Utility Boilers
          "Product Storage

          Valves, Pumps, etc.
 .   TOTAL             .
                                    Thermal  Oxidizer
                                   Catalytic Converters
                                   Floating  Roof Storage
                                   . Tanks
                                      Maintenance
                               50.0
                              270.0

                               ; 0.3
                                0.2
                               : 0.1

                               '. 0.1
                                7.7*
                                0.4
                               24.4*
Source:  Colony Development Operation, 1977, except those quantities noted
         with an asterisk (*) were estimated by SWEC.
.5.1.5  Carbon Monoxide Control
     Carbon  monoxide  (CO)  is usually  formed  by  incomplete  combustion of
fossil  fuels.    Normally,  an  excess  of oxygen  is  supplied  to a combustion
process  to  ensure that all of  the  carbon  in the fuel  is converted to carbon
dioxide  (COa)-   When a shortage of oxygen  occurs in the combustion process,
some  of  the  carbon  is  only  partially oxidized  to CO.   Federal  and State
standards  and  regulations  limit CO  emissions  because  of  their' deleterious
effect on the human  respiratory system.
                                     229

-------
     The  easiest and most  cost-effective way to  control  CO emissions is to
use excess  oxygen  in the cpmbustion processes to  ensure complete combustion.
When  incomplete combustion  does occur,  catalytic converters  or  thermal or
chemical oxidizers may be used to oxidize the remaining CO to CQ^.

     Inventory of Control Technologies—

     Figure 5.1-17  shows a  list of  the  applicable carbon  monoxide control
technologies,  and  Table 5.1-25  describes  in  detail  the features  of these
control methods.

     Complete fuel combustion  controls  CO emissions by  not  allowing them to
be  formed.   This  is done  by  operating  with  enough  excess   air  to ensure
complete oxidation of all  carbon to C02 instead of only partial oxidation to
CO.   When CO  is formed in  a  combustion process, a catalytic 'converter or
thermal or chemical oxidizer can be used.                         ;

     Carbon Monoxide Control Technologies Analyzed—             ;

     Diesel  equipment  will  be  used  in  mining  activities,  processed shale
handling,  and  transportation   systems  at  the  TOSCO II  facility.    The CO
emissions from  these  sources are controlled by using catalytic converters on
all diesel  engines.   Since  the catalytic converters also control hydrocarbon
emissions, they  have been included under hydrocarbon emission control.

     Process  fuels  are  burned  in  the thermal  oxidizer,  ball  circulation
system,  and process  heaters/furnaces and utility  boilers.   The ;CO emissions
from  these  sources  are controlled  by operating  the  units  with 20  to  25%
excess  air  to ensure complete oxidation of  all   carbon  to  C02.  This  is a
standard combustion practice,  so no additional equipment  or cost is associ-
ated with it.                                                    !     .    .

     Total Carbon Monoxide Emissions—

     Table 5.1-26 summarizes the carbon monoxide emission sources and control
equipment used for the emissions.

5.1.6  Control of Other Criteria Pollutants
         •                                   .                     i

     In addition to the primary air pollutants discussed so far, there may be
other  criteria  pollutants,  such  as  lead, mercury,  beryllium and fluorides,
emitted  from  the TOSCO II  facility.   Some of these  pollutants are nonvola-
tile;   therefore,  they  may  be  released only  as  fugitive  dust  constituents.
Any control  of  the dust will  also serve to control  the nonvolatile pollut-
ants.   Volatile  pollutants  may potentially  be released with the stack gases.
Some pollutants  do not  occur naturally and some are  unlikely to form during
oil shale processing.

5.1,7  Control of Noncriteria Air Pollutants

     Meaningful test data are not available to determine whether emissions of
noncriteria air  pollutants  are  a concern.   Consequently, no information on


                     . •   •            230

-------
      CARBON MONOXIDE
          CONTROL
        TECHNOLOGIES
                                    COMPLETE FUEL
                                     COMBUSTION
                                     CATALYTIC
                                    CONVERTERS
                                     THERMAL
                                     OXIOIZERS
                                     CHEMICAL
                                     OXIOIZERS
SOURCE • SWEC
      FIGURE 5.1-17  CARBON MONOXiOE CONTROL TECHNOLOGIES

                            231  '

-------























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               TABLE  5.1-26.   TOTAL CO EMISSIONS FROM THE PLANT
Stream
Number
10
18
19
91
104
118
119
125
138
179
' TOTAL
Emission Source Control Description
Mine Vent . —
Raw Shale Preheat —
System
Ball Circulation
System
Hydrogen Furnace —
Coker Feed Heater
Gas Oil Heater
Gas Oil Recoil er
Naphtha Heater
Diesel Equipment Catalytic Converters
Utility Boilers _-
CO Emissions
; (Tb/hr)
440.0
43. 9
2.8
9.9
; 1.0
0.4
. 1.4
0.2
23.0*
2.6
525.2

Source:  Colony Development Operation, 1977, except the quantity  noted with
   :      an asterisk (*) was estimated by SWEC.
control  technologies  for  such  pollutants  was  generated  for  this manual.
Mention of  species  such as POMs (U.S.  EPA,  1980) and trace elements such as
arsenic (Fox,  Mason and  Duvall,  1979; Girvin,  Hadeishi  and  Foxj, June 1980)
are noted.

5.2, WATER MANAGEMENT AND POLLUTION CONTROL

     As in  other industries  and  oil  shale  operations,  the TOSCO II plant—
from mining activities  to final product  and waste disposition—will produce
water  effluents  which  will  require  proper  disposal.    These  effluents  may
contain the following pollutants:

     ••    Suspended Matter, Oil and Grease

     •    Dissolved Gases and Volatiles

     •    .Dissolved Inorganics                                          .

     •    Dissolved Organics.
                                     233

-------
     This  section  describes  the  current,  commercially  available alternate
systems  for  controlling the  above  pollutants.   The  following,  subsections
provide  inventories  of  control   technologies  for  each  of  the pollutant
classes,  a discussion of advantages  and  disadvantages, and  important points
to  consider in selecting a particular  technology.   The performance, design,
and cost data  for the leading technologies are also presented.

5.2.1  Suspended Matter, Oil and Grease                          ;

     Undissolved  matter found in  wastewater  effluents includes solid parti-
cles  as  well  as oils and  greases.   The solids are usually the raw and pro-
cessed shale  particles  that are washed into  the  retort water  and those that
are entrained  in  the retort vapors and subsequently  removed in the gas con-
densates.   The retort water and gas  condensate also  contain trapped oil and
oil-in-water emulsions.   Service  and storm runoffs contain  suspended matter,
as well  as oils and greases.   Also,  the source water  contains  suspended soil
particles  and  debris.

    . In general,  the control  of suspended matter at oil shale  plants will be
accomplished  using conventional  technology.   For example,  clarification in
gravity  settlers   (with  addition  of  flocculants) and multimedia filtration
will, in most  cases, provide adequate control.  Associated energy consumption
and costs  are  generally low.

     The control of undissolved oils  and greases in oil shale wastewaters has
not been  studied  in detail.   API-type gravity settlers have  the potential to
provide  adequate  control  for most  of  the waste  streams  generated.   It is
possible,  however, that some wastewaters will contain  oil-in-water emulsions;
if so, additional  control steps may be required.   Heating the water or adding
chemicals  may  be  sufficient  to  break  the  emulsion;  otherwise,  filter
coalescence (or possibly ultrafiltration) may be required.       :

     The degree to  which emulsified oil'needs removal  is dependent on down-
stream  processing  and  reuse.   In cooling  towers,  the oil  may foul  heat
exchange surfaces  and thus require prior removal.   Similarly, fouling, and
possibly foaming,  may occur  when stripping the retort water or gas conden-
sate.   The extent to which such problems will arise is not known.

     The energy consumption and  cost of oil  separation  by  gravity means are
generally  low.  Thermal  or  chemical treatment, if required, would cause some
increase in  costs.   Filter coalescence  and,  in  particular, ultrafiltration
generally  are  more costly  and  would be considered only  if other procedures
prove inadequate.                .

     Inventory of Control Technologies-'-
           _          .     .-               -             •          ,         \
     Figure 5.2-1 shows different types  of technologies that apply to control
of suspended matter and oils and greases.   Key features of these technologies
are provided in Table 5.2-1.                                     :
                                     234

-------
   SUSPENDED  i
 MATTER, OIL 8
 GREASE CONTROL
  TECHNOLOGIES
                                  GRAVITY
                                 SEPARATION
                                CENTRIFUGATION
                                  PHYSICAL/
                                  CHEMICAL
                                  FILTRATION
 API-TYPE
 SEPARATORS

•SEDIMENTATION

 FLOTATION
 COAGULATION-
 FLOCCULATION

• CHEMICAL SEPARATION

.THICKENING




•SOLIDS FILTRATION

•FILTER COALESCENCE

• ULTRAFILTRATION
SOURCE' WPA
  FIGURE 5-2-1  SUSPENDED MATTER, OIL AND GREASE CONTROL TECHNOLOGIES

                                  235

-------











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      API-type separators.   For  gravity  separation  of  oil  in  large  holding
 tanks,  separators should  be  designed within the following  limits:  (a) hori-
 zontal  velocity of less than  3  fpm,  (b)  depth  between 3-8 ft,  and (c) depth-
 to-width  ratio  of  approximately 0.4.  Oil  is  skimmed  from the  surface  and
 collected for  reuse  or disposal.  Gravity  separation  is  not  effective  for
 emulsified  oils  that  might  be  present in  some  retort  waters  (American
 Petroleum Institute,  1969).
                                                                 |
      Sedimentation.   This  is a  gravity  process  in  which the solid  phase
 settles  and,  is  withdrawn  as a slurry.   Clarification may be carried  out  in
 large holding  ponds,  plate (lamella)  settlers  or hydrocycTones.   Chemicals
 (flocculants  and coagulants)  may  be added to precipitate salts  (softening)  or
 to  aid settling of suspended  solids (Humenick,  1977).

      Flotation.   This is a gravity process  in which the solid  phase rises  to
 the  surface  and  is  skimmed, off as a  slurry.   Air  bubbles may  be  introduced
 into  the  flotation vessels  to  assist  separation  (Humenick,  1977)1

      Centrifugation.   This is a modified  gravity method to  afford  separation
 or  settling of fine, suspended matter and oils.  The  wastewater1is  subjected
 to  a radial  force  greater  than  the  gravity  field by  rapidly rotating it.
 Suspended matter denser than  water moves radially away  from   the  center  of
 rotation,  while  the  lighter  matter  moves  toward  the center.    Concentrated
 matter can  be removed periodically or  in  a continuous  manner.   For  continuous
 operations,   the  sludge  should   be   fluid to  facilitate its  removal.  The
 technology  may not be applicable to highly viscous fluids.       !
                                                                 i
      Coagulation - flpeculation.   Fine particles  suspended  in [a  fluid are
 subjected to  size   enlargement   by  addition  of  chemicals  (coagulants and
 flocculants),  then  allowed to  settle by gravity or under  applied  force.
 Gentle agitation alone  sometimes  may  afford the  flocculation  of the  parti-
 cles.  The  technology may also be applicable to  liquid dispersions and  liquid
 particulates.

      Chemical  separation.   Addition  of chemicals  to  break emulsion  may  be
 used  in   conjunction  with  filtration  and is  normally  followed  by gravity
 separation.    The type and dosage of chemicals required is determined by  trial
 (American  Petroleum  Institute,  1969).   Chemicals  may  also   be   added   to
 precipitate salts or  to increase crystal size.

      Thickening.  Slurries  previously obtained  from gravity, centrifugation,
 and filtration: methods can be further concentrated, or thickened, by addition
 of chemical  agents or binders.  The thickened slurry may then be'subjected  to
 the   same  methods  for  final  disposition  (Adams  and  Eckenfelder,   1974;
Humenick,  1977).

     Solids  filtration.  The  water stream is passed through  a  filter medium
which holds back the  solid phase.  Filters  may  be  of the fabric type,  as  in
plate and frame,  rotating  drum (vacuum) and cartridge units, or granular, .as
 in  sand filters.   Filtration is generally more  expensive than  sedimentation
but can remove smaller particles (Humenick, 1977).
                                     237

-------
      Filter coalescence.   Gravity  separation  of oil  from water  is  standard
 industrial   and  refinery  practice;   however,  the  API-type  separators  are
 inadequate  for  very  small  oil  particles.   One  very  important  method  for
 removal  of  small oil  droplets  is coalescence  (Water Purification  Associates,
 December 1975).

      When  a  dispersion  of  micron-sized  droplets  of  one  liquid  (oil)  in
 another  (water)  flows  through  an  appropriate porous  solid,  coalescence of the
 dispersed  phase  is  induced  and  separation  of  the liquids  results.   The
 dispersed phase  can  be  allowed  to  accumulate  without  leaving  the  porous
 medium,  with  periodic  regeneration to  remove accumulated oil.

      Filter media are  usually either  the  packed fibrous  type .(e.g.,  fiber
 glass,  steel  wool)  or unconsolidated  granular materials (e.g. ,• sand,  gravel,
 crushed  coal).    Because  of  their large specific  surface  and; high  voids,
 fibrous  media are usually more  efficient  in removing droplets for  a given bed
 depth than  are  granular  media.   However,  fibrous media are  more  susceptible
 to  blockage  by suspended  solids and  are  more  difficult  to regenerate,  in
 addition to being more costly  than most granular  media.          :

      Advantages  of  filter-coalescers  include  high separation  efficiency  for
 dilute  suspensions  of very small  droplets,  potentially small  space  require-
 ments,  the  possibility of  continuous  operation,  and the  potential  for  the
 recovery of  the  dispersed  phase.  Disadvantages  of this  process  are  that
 suspended solids can  accumulate  to require  frequent medium regeneration  or
 replacement,  and  pumping  costs can be  substantial.   As  far as  is known,  the
 system  has  not  been  evaluated on  retort waters, and extensive pilot'plant
 testing  would  be  required  to determine  its  feasibility on  these  waters.

      Ultrafntratlon.   Passage  through  a  submicron-sized  membrane   filter
 separates  emulsified  oil  as   well  as  suspended matter and  large  organic
 molecules (MWt  £ 1,000).   The oil  droplets are  collected in the concentrate
 and removed by gravity separation.  This  process  is  significantly more  costly
 than  normal  filtration (Water Purification Associates, December 1975).

      Control Technologies Analyzed—

      The  streams  that  require removal of suspended  matter,  oils and greases
 are:               ..

      •    River Water  (stream 140)                               .

      *    Foul Water (stream 29)

      *    Runoffs and  Leachates (streams 12, 177, 178)

      *    Slowdowns  and Concentrates (streams 168, 169, 175 or 176).
                          	      •  •         '  -     .         i
      Colony has proposed  obtaining the river water  from the Colorado  River.
While  it does not contain  any oils  and greases, it  does contain suspended
matter.  Sedimentation by gravity settling and clarification with addition of
a!urn  are  the  approaches  proposed to reduce the suspended matter n'n the river
water.


                                    238

-------
      Table 5.2-2 presents  the  design features  and  cost  data  for clarifi-
 cation,  and Figure  5.2-2 shows a cost curve for the clarifier.   This activity
 could be  considered as part  of the  process  rather  than  pollution control.
         TABLE 5.2-2.   DESIGN AND COST OF RIVER WATER CLARIFICATION*
Item
River Water Flow Rate.
Flow Rate/Clarifier
Number of Clarifiers
Retention Time
Diameter
Alum Rate (30 ppm)
Fixed Capital Cost
Direct Annual Operating Cost
Maintenance @ 4%
Alum @ 12
-------
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   TABLE 5.2-3.  DESIGN AND COST OF API OIL/WATER  SEPARATOR  FOR  FOUL WATER

Item •'-,'..
Foul Water Flow Rate
No. of Channels (1 standby)
Channel Cross Sectional Area
Channel Depth
Channel Width
Channel Length
(channel is covered)
Fixed Capital Cost3
Direct Annual Operating Cost3
Maintenance @ 3%
Total Annual Control Cost0
Unit
gpm
103 Ib/hr
— '
ft2
ft
ft
ft
$103
$103

$103
Quantity
498
253
2
24
3 -;
8
65
140

3.4
31

3                                          '
  The fixed capital cost and direct annual operating cost for the standby
  channel are included.                                          ;

  Maintenance is based on the fixed capital cost less contingency.

  See Section 6 for details on computation of the total annual control cost.
                  : '            • • '                    '            i
Source:   WPA estimates based on information from American Petroleum
         Institute, 1969.     ,
     Service and  fire water  runoff,  storm  runoff,  and leachate  from shale
piles  may  contain  oily  materials.  Again,  an API-type  oil/water separator
(without channel covers)  was  examined  as the  control.   This  will  also allow
separation of  suspended  matter  along  with  the  water.   The  cost  and design
data  for  this  separator are  given in  Table 5.2-4, while  a cost  curve  is
already included in Figure 5.2-3.
                                     241

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                  242

-------
           TABLE 5.2-4.   DESIGN AND COST OF API OIL/WATER SEPARATOR
                           FOR RUNOFFS AND LEACHATE
Item
Runoff Flow Rate
No. of Channels (1 standby)
Channel Cross Sectional Area
Channel Depth
Channel Width
Channel Length
Fixed Capital Costa
Direct Annual Operating Cost3
Maintenance @ 3%
Total Annual Control Costc
Unit
gpm
-
ft2
ft
ft
ft
$103
$103
$103
Quantity
126
. , 2
6
3 .
2
65 - •
27.4
0.7
8
:.....
  The fixed capital cost and direct annual operating cost for the  standby
  channel are included.                                          •  .

  Maintenance is based on the fixed capital cost less contingency.

  See Section 6 for details on computation of the total annual control cost.

Source:  WPA estimates based on information from American Petroleum
         Institute, 1969.
     The  blowdowns,  sludges, and concentrates  from various processing units
will  also  contain  suspended matter.   These  streams are  collected  in  an
equalization  pond  for possible  use in  processed  shale moisturizing.  Since
gravity settlement affords  separation of the suspended matter, the equaliza-
tion pond  also  might be viewed as  a  pollution  control.  Its design and cost
are  presented  in  Table 5.2-5,  and  a cost  curve  is  given  in Figure 5.2-4.

5.2.2'  Drssolved Gases and Volati1es

     Dissolved  gases  include ammonia, carbon dioxide,  and  hydrogen sulfide,
while  volatile  materials  are low  molecular weight  organics.   Methods  for
removing  these  substances  from  water are summarized in Figure 5.2-5.   Steam
stripping  is  the most  likely process to  be used  and has  been successfully
demonstrated on a  laboratory scale  for some oil shale wastewaters (Hicks and
Liang,  January 1981).
                                     243

-------
              TABLE 5.2-5.   DESIGN AND COST OF EQUALIZATION POND
 Item                 .                   Unit               Quantity

 Flow Rate  into  Pond                       gpm               2,600\
                                      acre-ft/yr            3,770

 Pond Area                                acre                   2.7

 Pond Depth                               ft                    10•

 Liner Material            ,                __                 Bentonite,

 Fixed Capital Cost                       $1Q3                 150;

 Direct Annual Operating Cost             $103

   Maintenance  @ 2%a                                            2.-4

 Total Annual Control  Cost5               $103               .   40 ,


  Maintenance is based on the fixed capital  cost  less contingency.

  See Section 6 for details on computation of the total annual  control cost.

 Source:  WPA estimates.



      Inventory of Control Technologies—

     Table 5.2-6  presents an  inventory of  applicable  control  technologies,
 along with their  key features, for the  dissolved volatiles.   Basically, most
 technologies involve stripping of the dissolved gases by either  elevating the
 temperature,  applying  vacuum,  or  displacement  with  carrier  gases.   More
 specific removal can  be accomplished by using an adsorbent selective for the
 gas  in question.                                                 :
                                                                 >
     Steam stripping.  Steam stripping  of sour waters (e.g.,  waters contain-
 ing  dissolved   ammonia  and hydrogen  sulfide)  and  coke-oven  liquors  (e.g.,
waters containing dissolved ammonia  and carbon dioxide) is standard practice
 in the petroleum and steel  industries.   Stripping has also been used as part
of  the  "Phenosolvan"  process  on  coal  gasification  process ! condensates
 (American Petroleum Institute,  March 1978; Beychok,  1967).

     The dissolved  gases  are  stripped  from the  solution  by  bubbling  steam
through it, generally  in  packed  or tray  columns.   The  steam  may be directly
sparged (live)  or used  indirectly in a reboiler, as in distillation columns.
The  stripped  gases,  along with  other  volatile  materials,  are  removed  in a
relatively  concentrated  gas  stream  which  may be  treated  for adsorption/

                                     244

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             DISSOLVED GASES
              a VOLATILES
               CONTROL
             TECHNOLOGIES
                                              STEAM
                                            STRIPPING
                                             VACUUM
                                            DISTILLATION
                                             INERT GAS
                                             STRIPPING
                                             ADSORPTION
     SOURCE:  WPA
FIGURE 5.3-5   DISSOLVED GASES AND VOLATILES CONTROL TECHNOLOGIES

                              246

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-------
 recovery  of a specific substance  or  incinerated.   Carbon dioxide  is  readily
 stripped  at efficiencies  of +99%;  ammonia  strips  less easily, and  pH eleva-
 tion  may be  required in  some cases  for  99% removal.   Hydrogen  sulfide  does
 not  strip as easily  as  carbon dioxide but  can  generally be removed  down  to
 the  10-20 ppm range.   Costs are for  equipment and  steam  and are  proportional
 to the volume of water to be treated.                           '

     Steam  requirements  range  from approximately 10  to  15 Ibs  steam per
 100 Ibs  water treated.   For  a given separation, a greater column  height  is
 required  for a  lower steam rate.   The  selection  of steam  rate and  column
 height is based on energy and equipment costs.

     The  stripped gases  may  be  incinerated  or treated  further to  recover
 ammonia  and  sulfur.   Ammonia  may be  recovered as anhydrous  ammonia,  aqua
 (20-30%)  ammonia  or  ammonium sulfate.  In cases where the sulfate  is  derived
 from flue gas desulfurization,  the sulfate  route may be  viable depending,  in
 part, on  the  marketability of ammonium sulfate  and on the  costs of alterna-
 tive flue gas desulfurization  processes.   Because  oil shale plants  generally
will have ammonia available as  a  by-product, S02  scrubbing with NH3 may  be
 attractive  when   the  technology   is  sufficiently  developed :and  tested.
 Recovery  of  anhydrous  ammonia  involves  considerable  capital  and   energy
 (steam) requirements,  but these are partially offset with by-product  ammonia
 sales.   The stability of the ammonia market  must be considered when  selecting
 a recovery process.                    ,

     Vacuum distillation,     Distillation   at   reduced   pressure   has  many
 industrial  applications,   but  these  primarily   involve  distillation   or
fractionation of compounds with high boiling points or low thermal stability.
The method  may be applicable  to stripping  of gases  and volatile compounds,
but the energy requirements are high relative to those for steam:or  inert gas
stripping.
                                                                          low
     Inert gas stripping.   This  method  is  applicable  to  dilute,  or   .,..
strength, wastewaters  for which  steam stripping may  not be practical.  The
operating principle is  similar  to  that  for steam  stripping,  except/air,
nitrogen, carbon  dioxide,  or other inert gases may be used.  Its application
to  high strength  liquids is  generally  not  practical because  large column
heights and gas compression costs are required.                  ,

     Adsorption.  Dissolved  gases and  volatile components may be adsorbed on
specific surface-active materials by passing wastewaters through ;a bed of the
adsorbent.   The  gases  may then  be desorbed  thermally,  and  the regenerated
adsorbent  is   recycled.   This  method  is  generally  used  in  trace  removal
applications.

     Control Technologies Analyzed—

     The streams  that  require  removal  of dissolved gases  and volatiles are:

     *    Foul Waters (streams 29, 30,  99)

     •    Sour Water (streams 110, 124).


                                     248

-------
      The  foul  waters  are  previously  freed  from  the  separated  oil  and  emulsion
 in  the oil/water  separator,  but  some  polar organics  (e.g., phenols,  fatty
 acids)  remain dissolved.   A  portion of the  dissolved organics ,can  be  steam
 stripped  along  with  other  dissolved  gases.   The foul  waters also  contain
 free  ammonia, hydrogen sulfide  and  carbon dioxide.  Steam stripping removes
 these dissolved gases  and most of  the volatile  organic matter.  A further
 control  of the  released ammonia  is also  desirable  and this  may be accom-
 plished with  an ammonia  recovery  unit.  Design parameters  and cost  informa-
 tion  for  steam stripping are given  in  Table  5.2-7, and  a cost  curve  based on
 this  specific  design  is presented in Figure 5.2-6.    The  description and
 material  balance for  the stripper are  presented in Sections  3.3..3 and 4.2.7,
 respectively.

      Steam  stripping  and ammonia recovery  were  examined as controls  for the
 sour  waters,   the design  specifications for the ammonia  recovery  unit for all
 case  studies  are  given  in  Table 5.2-8,  while the  costs are .presented in
 Table 5.2-9.   Figure  5.2-7 presents a cost  curve for  the ammonia  recovery
 unit  specifically  designed  for  treating the  TOSCO II  sour waters.   The
 process description  for  the  unit is given in  Section 3.3.11 arid a  material
 balance for the  process is included  in  Section 4.2.7.

 5.2.3 Dissolved Inorganics

      Dissolved  inorganics are  usually not  a  problem unless the compounds are
 judged  to  be  hazardous  (e.g.,  trace metals)  or  when  fouling of equipment
 (e.g., boilers)  occurs  because  of the  high salt  content of  the!waters being
 used.  Natural  waters  and waters that  come into  contact with the solids may
 need  to   be  treated  if they are  intended for  critical  uses  in  the plant.
 Processed shale  moisturizing, on the other hand,  may  not require control of
 dissolved inorganics.    In fact,  waters with high salt content can be  used for
 this  purpose,  thereby  avoiding the  need  for. other  controls.!   Since  gas
 condensates  do  not contain  significant amounts  of dissolved  inorganics,  a
 treatment may not be necessary.

      Inventory of Control Technologies—

     Methods  for removal  of dissolved  inorganics  are  shown in Figure 5.2-8,
while  some  of  the  key  features  of  the  technologies  are  presented  in
Table 5.2-10.   The operating  principles for  some of the methods ;shown in the
 figure are detailed below.

     Precipitation.   Chemicals may be added  to precipitate salts, e.g.,  lime .
addition  for  carbonate  (hardness)  removal.   Processed shale  is also believed
to behave like a  softener for  inorganic  carbon reduction  (Humenick, 1977).
The process is  simple,  but it will  usually require the use of other methods
(e.g., gravity separation, centrifugation,  filtration) to remove the precipi-
tate.           ...

     Ion exchange.   Cations and  anions in solution are replaced With hydrogen
and hydroxyl  ions on  exchange  resins capable of producing  a  water virtually
free of common salts.   The resins are regenerated with relatively strong acid
and alkali solutions,  and the regenerant wastes must be controlled.  Costs go


                                   ,  249

-------
             TABLE 5.2-7.  DESIGN AND COST OF FOUL WATER STRIPPER
Design Parameter
Foul Water Feed Rate
Steam Rate
Cooling Water Circulated
Stripping Column
Number
Diameter
Height
Material
Reboi 1 er
Number
Surface area
Material
Partial Condenser
IN umber
Surface area
Material
Feed Heat Exchanger
Number
Surface area (each)
Material
Fixed Capital Cost
Stripping column
Heat exchangers
TOTAL
Direct Annual Operating Cost
Maintenance @ 4%a
Labor, 12 hr/day @ $30/hr
Steam @ $3/MMBtu
Cooling water @ 3
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                           251

-------
TABLE 5.2-8.  DESIGN OF AMMONIA RECOVERY SYSTEM*
Design Parameter
Sour Water Feed Rate
Ammonia Rate
Steam Rate
Cooling Water Circulated
Electricity
Chemicals
H3P04
NaOH
Steam Stripping Column
Number
Diameter
Height
Material
•Reboilers on Steam Stripping Column
Number
Surface area
Material
Phosam Absorber
Number
Diameter
Height
Material
Reboiler on Phosam Absorber
Number
Surface area
Material
Cooler on Phosam Absorber
Number
Surface area
Material
Phosam Stripper
Number
Diameter
Height
Material
Unit
gpm
Ib/hr
103 ib/hr
gpm
kW

Ib/hr
Ib/hr

—
ft
ft
--

—
ft2
-—

—
ft
ft
„„ .

„=
ft2
«*«=»

• —
ft2
-—

--
ft
ft
—
Quantity
510
11 , 208
156
6,900
300

19
120

1
6.0 .
95
CS/SS

1
1,400
CS/SS

1
5
50
SS
• .
1
4,175
CS/SS

1
5,640 .
CS/SS

1 .
8
60
SS
                                              (Continued)
                     252

-------
                              TABLE 5.2-8  (cont.)
 Design  Parameter
Unit
Quantity
Condenser on Phosam Stripper
Number
Surface area (each)
Material
Ammonia Fractionator
Number
Diameter
Height
Material '•'..'
Fractionator Feed Tank
Number
Diameter
Height
Capacity
Material
Reboiler on Fractionator
Number
Surface area
Material
Condenser on Fractionator
Number
Surface area
Material
Flash Drum
Number
Diameter
Height
Capacity
Material
Lean Solution Cooler
Number
Surface area (each)
Material
Solution Exchanger
Number
Surface area
. Material

_=
ft2
=—

__
ft
ft . ;
' —

.
ft
ft
gal
-—

—
ft2
-—

—
ft*
-—

-
ft
ft
gal


„_
ft2-
— — , .

--
ft2
~

2
3,380
SS
i
1
3.8
64
SS

1
7
26
7,250
SS;

i
1,240
CS/SS

1
3,835
CS/SS

1
4
9;>-
820;
S5

2
4,625
cs/ss;
; •• • • -.-- . .
1
1,810
SS
* This table is based on the Phosam-W process, which is only one example of
  many available processes for the recovery of ammonia.

Source:.  WPA estimates based on information provided by U.S.S. Engineers and
         Consultants, Inc., April 1978.
                                      253

-------
                    TABLE 5.2-9.   COST OF AMMONIA RECOVERY
Item Unit
Fixed Capital Cost $103
Towers
Heat exchangers
Drums, etc.
TOTAL
Direct Annual Operating Cost $103
K
Maintenance @ 4%
Labor, 24 hr/day @ $30/hr
Steam @ $3/MMBtu
Cooling water @ 3$/m3 circulated
Electricity @ 3$/kW-hr
Chemicals
NaOH (475 tons/yr @ $350/ton)
H3P04 (75 tons/yr @ $474'/ton)
TOTAL
Credit for Ammonia Sales @ $110/ton $103/yr
Credit for Low Pressure Steam Return $3/MMBtu
Total Annual Control Costc $103
Quantities
Example Ia 'Example IIa

1,945 2,035
2,614 2,729
100 105
4,659 '. 4,869

152 158
237 i 237
2,653 2,834
345 . 369
71 76

166 • 180
	 35 : 	 38
3,659 ; 3,892
4,878 ! 5,203
183 229
(122)d --*

  In Example I, the foul water stripper overheads are not fed to the ammonia
  recovery unit.  Example II reflects recovery of additional ammonia from the
  foul water stripper overhead.

  Maintenance is based on the fixed capital cost less contingency.

c See Section 6 for details on computation of the total annual control cost.

  Value in parentheses ( ) indicates that the annual by-product credit is
  higher than the total annual control cost.
Q
  Example .II is not part of the case studies; therefore, the total annual
  control cost was not determined for it.

Source:   WPA estimates based on information provided by U.S.S. Engineers and
         Consultants, Inc., April 1978.
                                     254

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                       255

-------
      DISSOLVED INORGANICS
      CONTROL TECHNOLOGIES
SOURCE: WPA
                                      CHEMICAL
                                    PRECIPITATION
                                    ION EXCHANGE
                                     MEMBRANE
                                    PROCESSES
                                    EVAPORATION
                                    FREEZING
                                     SPECIFIC
                                    ADSORPTION
                                                        REVERSE
                                                       ' OSMOSIS (RO)
                                                     L- ELECTRODIALYSIS(ED)
                                                     i—THERMAL
                                                        VAPOR
                                                        COMPRESSION
        FIGURE  5.2-8   DISSOLVED INORGANICS CONTROL TECHNOLOGIES

                                   256

-------



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 up with  increasing  concentration of  salts  in the  water.   Ion  exchange is
 normally used  only where  a  very clean  water is required  from  a relatively
 clean or mildly brackish  supply.   The brganics present are not  removed and
 may foul  the exchange resins  (Calmon and Gold, 1979).           :

      Reverse osmosis (RO).    Sometimes  called  "hyperfiltration;"  RO  is  a
 process  for recovering, relatively pure water from solutions.  Water is passed
 through  a  hyperfiHer,  or semipermeable  membrane,  which  rejects  dissolved
 materials.    As  in  normal  filtration,   the   driving  force  isi  hydrostatic
 pressure,  but  in  this  case,  the pressure  has  to  be  greater than the osmotic
 pressure  of the solution.  Osmotic  pressures  are related to the  total  molar
 concentration  of  the   solution  and  its  temperature   (Hicks   and  Liang,
 January  1981).

      The  water is  passed  under pressure  (greater  than 200  psi) through  a
 membrane  which is  impermeable  to  most  inorganic salts  and many  organics.
 These "rejected"  substances   remain  in  a concentrate  stream which may  be
.10-20% of the feedwater volume.   The  treated water or permeate will  generally
 contain  less than  10%, and often less than  1%,  of  the rejected  substances.
 Costs scale  primarily  with the  volume of water  to  be treated but  are  also
 dependent   on  concentration.    At  very  high  solute  concentrations  (e.g.,
 seawater),  costs increase  rapidly due  to the  high applied pressures  that are
 required. The flux of water through the membrane,  i.e., the  permeate  recovery
 rate,  increases  linearly  with  the  pressure  by  which  the  applied  pressure
 exceeds  the  osmotic  pressure.   Fluxes of 10  gal/ft2/day have been  measured
 for  retort water  at  an  applied pressure   of  600  psi.    Typical   applied
 pressures for brackish  waters  range from  200 to 600 psi and  greater.
                          _ • .      • _          ......     ...   .       j
      Membranes  consist  essentially of a  thin  skin (0.1 to 0.25 urn) of active
 chemical  (cellulose acetate,  polyamide)  on a  porous  substructure, which  may
 then  be  housed in a spiral-wound module for commercial  application.  Other
 geometries  are  also available.  Rejection  of  strong  electrolytes  is  normally
 in  excess   of  90%  and  can  exceed 99 percent.  Nearly  complete rejection  is
 obtained  from  most  species with molecular weights  greater  than  about  150.
 However, low molecular  weight nonelectrolytes  (e.g., small  organic molecules
 like  urea,  and  weak acids  such as boric  acid) are  poorly rejected.  Rejec-
 tions  of these  substances can  sometimes be  improved by adjusting the  solution
 pH  to a  value where  the  compound  dissociates  (e.g.,  boron  is rejected above
 PH ==  io).                                               .-.;-.
                                                                 \ •     •    •

      Some advantages  of RO  treatment are the low labor and space requirements
 and the  high rejection  rates obtained for  a wide  range of dissolved  contami-
 nants.   Of  particular  relevance  to  oil   shale  retort water  is  that  both
 organic and inorganic compounds can be simultaneously removed under favorable
 pH  conditions  and  that  such  a system can accommodate changing  water flow
 rates.   A   serious  disadvantage  of  the  process   is  that the  membranes  are
 susceptible  to  blockage  by deposition of  solids.   This  so-called  fouling .
 results from solids  present  in the  feed solution or  from  precipitation of
 solids as the concentration in the brine exceeds the solubility limit; it  may
 even result from biological  activity on the membrane surface.    :
                                     258

-------
     Fouling  rates  may be reduced by proper pretreatment and by reducing the
concentration  increase in the  brine.   Reverse  osmosis  does  not destroy the
pollutants,   it  merely  concentrates  them  into  a  smaller  liquid  stream.
Reducing the  concentration increase implies reducing the product recovery and
increasing  the  amount  of  brine  for  disposal.   Fouling  can be  further
controlled  by periodic washing, although there  is generally a certain amount
of  irreversible  fouling that  determines  membrane  life  and operating costs.

     Costs  scale proportionately with the volume of product water recovered,
but  they  are  also  dependent on the degree of  recovery  and membrane fouling
characteristics.   As the concentration of pollutants in wastewater increases,
so does the osmotic pressure; hence, higher applied pressures are required to
maintain  the  desired  permeate  flux.   Energy  costs,  however,  are  normally
small relative to membrane costs.                                !

     Electrodialysis (ED).   Electrodialysis  is  the  use of  an  electromotive
force  to  transport ionized  materials in a solution through  a  diaphragm, or
membrane.    The process can be made selective by using ion-specific membranes
which allow passage of only certain  ions.  A  common  application of electro-
dialysis is in the desalting of brackish waters containing 1,000-5,000 ppm of
salts.   A removal efficiency of 90-99% is usually achievable.

     Thermal evaporation.  This  approach  includes .processes in which heat is
applied  to   vaporize  water,   leaving  a concentrated  solution or  slurry for
disposal.    The high  energy  required  for evaporation  is recovered  in  most
processes by  condensing  the  water vapor and,  as a result, producing a stream
of  relatively pure water.   Volatile contaminants,  if present, may  require
removal in an upstream stripping process in cases where a clean product water
is necessary.  Multiple  effect boiling (MEB)  and multistage  flash  (MSF) are
two procedures commonly  used for evaporation (Water Purification Associates,
December 1975).

   '  Disadvantages of  thermal  processes  are  that volatile substances are not
controlled,   and  (energy) costs  are  generally higher than  for  processes not
involving a  phase  change.    Problems  related  to scaling  of h£at  transfer
surfaces and  corrosion are also encountered.   These problems may be accentu-
ated with waters containing  high organic loadings, such  as  oil  shale waste-
water.   Thermal processes  may find application  if there  is  a need for dirty
steam,  as occurs  in many in situ processes.

     Vapor compression evaporation.  This  is  a  method  for  evaporating water
by the  use  of mechanical energy.  Thermal energy required for evaporation is
obtained by mechanical  compression of the vapor  instead  of  by  heating.   The
wastewater  is  boiled  in  an evaporator to produce a vapor which is  compressed
in order to raise its temperature, and then it is passed through :the tubes in
the,  evaporator where  the  necessary  heat exchange  between  the  vapor  and
wastewater takes  place.  The vapor cools and condenses upon heat exchange and
a relatively pure water is produced.                              :

     The advantage  of  vapor  compression  is that  the heat  required for vapor
formation is  recirculated  so that the amount  that must be dissipated is much
less  than  the  latent  heat  of  vaporization.   This  approach; results  in

                                     259

-------
 relatively  low energy  requirements  and essentially negligible cooling  water
 requirements.   The penalties are the  high  capital  costs associated with  the
 compressor,  which  must handle  the  large  volumes  of  vapor,  and  increased
 maintenance  costs.   Other disadvantages of  vapor compression  evaporation  are
'similar  to those  of the thermal  processes.

      The energy  required  for the single  effect vapor  compression units  is
 about 70-90  kW-hr per thousand  gallons  of product  water.   Some single effect
 vapor compression units (RCC evaporator) can  recover  up to 98% of  the waste-
 water containing  up to  11,000 mg/1 total dissolved  solids.      :

    .  Freezing.  The water is reduced  in temperature to  produce a solid  (ice)
 phase and a  concentrated  brine.  The ice  is washed  free  of salts and then
 melted to produce a virtually pure  water.   Both inorganics and organics  are
 removed  in  the brine stream.  Since the costs scale with the  volume of  water
 to  be treated, freezing would normally be applied  to  relatively concentrated
 low volume  wastes.   While this  process  is  theoretically more efficient than
 evaporation,  it has yet to  be applied commercially.   It is included in this
 inventory as  it  may  be  useful  for  controlling  retort   waters,  provided
 operating problems can  be resolved in  the  future (Barduhn,  September  1967;
 Water Purification  Associates, December 1975).

      Specific  adsorption.  The processes in this category  are similar to  the
 ion   exchange   processes,  except  that  the  affinity   between  the  sorbent
 materials  and  the  solutes   being   removed  is  of a  physical nature.    The
 sorbents  may  be  natural  or synthetic  and usually  have  pores,  or lattice
 vacancies, of  uniform size and dimensions which are specific for the solutes..
 The  processes  are  not applicable  to  high  strength  wastewaters and  are
 generally used  for  trace removal applications.

      Control Techno!ogles Analyzed—

      The  following  streams   may require  control  of dissolved  inorganics:

      •    Boiler  Feedwater (streams  153, 154, 155, 156,  157)    '
      »    Cooling Water (streams 141, 142, 143, 144, 145, 146).

      Softening  was  examined  as  the  most economical  treatment of  the  river
water makeup to prevent seal ing'in the boilers.  In this process,  calcium  and
magnesium  ions are  replaced by sodium  ions  using  a  zeolite ion exchange
 resin.  Total dissolved solids and silica are not removed by softening, and a
 relatively large  boiler blowdown is required  to  maintain acceptable concen~
tration  levels in  the  boilers.   The  boiler  blowdown  is used for processed
shale moistening.   The blowdown does represent an energy loss from the boiler
system, and  some  heat recovery from this stream  might prove cost effective.
The zeolite softener is regenerated with a saline solution prepared from salt
and  clarified  river water.  The waste regenerant,  containing  mainly calcium
chloride, is disposed of on the processed shale after equalization with other
blowdowns.   Table 5.2-11  gives  the  basis  for  design  and  costs   of  boiler
feedwater treatment, while a cost curve for the  zeolite system ITS presented
                                     260

-------
 in  Figure 5.2-9.   The boiler feedwater  treatment  could  be  considered  as  part
 of  the process  rather than  pollution  control.


       TABLE 5.2-11.   DESIGN AND COST.OF BOILER  FEEDWATER TREATMENT3
Item                                            Unit',..         .Quantity

Boiler Slowdown  (20% of softened                 gpm                280
  river water makeup)

Steam Consumption and Losses                     gpm              1»120

   TOTAL MAKEUP  (clarified river water)          gpm             ; 1,400

Fixed Capital Cost (includes one spare train)   $103

   Resin:  940 ft3 @ $50/ft3                                     .47
   Installed equipment                                              361
   Contingency and contractor fee                                    83

      TOTAL                                                         491

Direct Annual Operating Cost                    $103

   Maintenance @ 4%b                                             ;    14'
   Labor, 2 hr/regeneration @ $30/hr                             '    66
   Chemicals
      Resin replacement @ 3% per year                                 2
      Salt @ $45/ton                 .                            :   290

      TOTAL                                                         372

Total Annual Control Costc                      $103                474


* This technology could be considered as part of the process rather than
  pollution control.

  Maintenance is based on the fixed capital cost less contingency.

  See Section 6 for details on computation of the total annual control cost.

Source:   WPA estimates based on information from Peters and Timmerhaus, 1980.
     Clarified river water  is  used as cooling tower makeup.   As a treatment,
some sulfuric acid  is  added to convert calcium carbonate to the more soluble
calcium sulfate.  The  cooling  tower is operated at  two  cycles of concentra-
tion, which means that the concentration of dissolved species in the blowdown
is twice that in the makeup.   Since this concentration is not excessive, the
                                                                 I

                                     261

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 cooling,  tower  (slowdown  may   be   used  for  processed  shale  moisturizing.
 Table 5.2-12  contains  design  and  cost  information  for  the  cooling  tower
 makeup  treatment,   and  a  cost   curve  for  the   treatment  is   shown  in
 Figure 5.2-10.  This technology  could  be considered  as part of the  process
 rather than pollution control.
           TABLE 5.2-12.  DESIGN AND  COST OF COOLING WATER TREATMENT3
Item
Evaporation and Drift Losses
Slowdown
TOTAL MAKEUP (clarified river water)
Cycles of Concentration
Su'Jfuric Acid Addition
Unit
gpm
gpm
gpm
--
mg/1 (ppm)
ton/yr
Case
A, B
1,530
1,530
3,060
2
71
428
Studies
C
1,646
1,646
3,292
2
'71
461
Direct Annual  Operating Cost                      $103

   Sulfuric  acid @ $65/ton                                       28        30

Total Annual  Control  Cost                                        29        31
.n^™~!T'~--.-.-"-"i-"'•••'-'-.,_ -_   ~""~^~:.-~.".  _r_ll_ll[MJ.'",T""J".^V.'L'J"L.'. - '  '1.1..Z"""~.   ".__"'"C"V~; ':.''  .' T~rrr""T'-:i- "". ' ' _•__;	. --..I. I.	  I....	
        /•'.".          '                   '                    '<         ' """"
  This technology could be considered as part of  the  process  rather than
  pollution  control.                                              ;

  See Section  6  for  details  on computation of the total  annual  control cost.

Source;   WPA estimates based on information  from  Peters  and Timmerhaus, 1980.
     Other Control  Technologies Analyzed—

     One additional  dissolved inorganics control technology—a solar evapora-
tion pond—was evaluated as a post-treatment for the  process  waters.   A solar
pond is  simply a lined  pond with enough  surface area  to  provide an evapora-
tion rate  that  is  higher  than  the  rate of  inflow.   The  precipitated sludge
can  be  removed  periodically  and  disposed  of  in  a  proper manner.   This
technology  has not  been proposed  by Colony;  however,  it was analyzed  as a
viable  option in the  event that the  process waters  are  reused 'in  the plant
and the resulting wastes are disposed of separately from the  processed shale.


                                      263

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                       264

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      For example,  the foul  water after steam stripping can be concentrated by
 evaporation,  whereby  most  of  the  water and  volatile  components  would  be
 removed.   The  foul  water  concentrate  can then  be  subjected to  chemical
 oxidation to destroy  nonvolatile  organics.   At this point,  only  nonvolatile
 inorganics  should  remain  in  the oxidized  sludge.   The  sludge can then  be
 placed   in  a   solar  evaporation  pond  for  further  concentration  of  the
 inorganics.   If the  treated foul  water  is  used  as  makeup to the boilers  or
 cooling  tower,  the blowdowns from these  operations  can also  be  placed  in  the
 solar pond.   A flow  scheme  depicting the above treatment  and reuse options,
 when  applied specifically  to the TOSCO  II  process  waters,  is  'presented  in
 Figure 5.2-11,  the  design and cost data are  given  in Table 5.2-13, and  a cost
 curve for the pond  is  presented  in Figure 5.2-12.


          TABLE 5.2-13.   DESIGN  AND  COST  OF  SOLAR  EVAPORATION POND
 Item                                     Unit                  Quantity
Flow Rate, to Pond                         gpm                     214
                                      acre-ft/yr                 . 311

Evaporation Rate                         in/yr                     15

Pond Area                               acres                     300

Liner (chlorosulfonated polyethylene)   103 ft2                13,000

Fixed Capital Cost                       $103                  16,600

Direct Annual Operating Cost             $1Q3

   Maintenance @ 2%*                                              270


* Maintenance is based on the fixed capital cost less contingency.

Source:   WPA estimates.


5..2.4  Dissolved Organics

     Removal of volatile organics by stripping may be sufficient for reuse of
process  waters  in  processed shale moisturizing; however, nonvolatile organic
components  are  not  removable  by stripping.   Therefore, for  higher quality
uses, further treatment may be necessary.   Some of  the available approaches
are discussed below.

     Inventory of Control  Technologies—

     The technologies  available  for dissolved organics  control  are  shown in
Figure 5,2-13 and are described in Table 5.2-14.
                                     -*,

                                     265

-------
    FLOWS IN 6PM
          FOUL WATER
SOUR WATER
LOSSES
[3D •
498
FOUL WATER
STRIPPER



510

AMMONIA
RECOVERY

468

19
LOSSES
,487 1,
VAPOR
COMPRESSION
EVAPORATION
441
i
46
CONCENTRATE
WET
AIR
OXIDATION
TO HYDROTREATERS '
485 *
	 H 	 _. rn 7IH CUD nr^nurn
LOSSES
J2I4
45 SOLAR
SLUDGE POND
BOILER ' ' . .
FEEDWATER
J848
CARBON
ADSORPTION

441
CLEAN WATER
STEAM
GENERATORS
i
169'
SLOWDOWN
' 1 120
SOURCE: WPA
     STEAM
         FIGURE  5.2-11 FLOW SCHEME FOR SOLAR EVAPORATION TREATMENT
                                  266

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 DISSOLVED  ORGANICS
 CONTROL TECHNOLOGIES
SOURCE' WPA
                                   BIOLOGICAL
                                   WET AIR
                                   OXIDATION
                                   CHEMICAL
                                   OXIDATION
                                   THERMAL
                                   OXIDATION
                                   MEMBRANE
                                   PROCESSES
                                   ADSORPTION
                                   FREEZING
                                   SOLVENT
                                  EXTRACTION
                                  EVAPORATION
                                  DISPOSAL AND
                                  CONTAINMENT
r REVERSE OSMOSIS (RO)


  •ULTRAFILTRATION(UF)


E  CARBON,

  RESIN      !

  PROCESSED SHALE
  STRIPPING

  COOLING TOWER

  SOLAR
        FIGURE  5.2-13   DISSOLVED ORGANICS CONTROL TECHNOLOGIES

                                 268

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      Biological treatment.   Biological   processes   may  be  aerobic,  where
 organics  are  oxidized to  carbon dioxide and water,  or anaerobic,  where the
 organics  are  reduced  to  methane.  Both approaches produce sludge as a waste.
 Aerobic processes  are  faster and less susceptible  to toxicity problems than
 anaerobic  processes,   but  oxygenation  equipment  is  required.   Bench-scale
 tests on retort waters have shown that minor changes  in retort water composi-
 tion  can  result  in  a significant  reduction in  the  performance of  a well-
 acclimated  system.   In  the  presence  of   biorefractory  (nonbiodegradable)
 organics,   powdered-activated  carbon may be  added  to  the  bioreactors  to
 achieve  acceptable reduction   in  organic  content.   Necessary  pretreatment
 includes stripping, pH adjustment, and nutrient addition; control of specific
 toxic materials may be required as well   (Adams and Eckenfelder,  ,1974; Hicks,
 et al., June 1979; Hicks and Wei, December 1980).                 ,

      .Wet air oxidation (WAO).   This  is  a procedure  for the  destruction  of
 organic matter  dissolved or suspended  in water  or  wastewater  by  oxidizing
 with air  at high  temperatures.   The temperatures used are  above  the normal
 boiling point  of  water,  and the reaction  is carried  out  under pressure  to
 prevent boiling.  The  pressure is usually 600 psig  or above.   The degree of
 oxidation   achieved  depends  on  the  temperature  and   the material  oxidized.

      The advantage of  WAO  is that the organics do  not have to be biodegrad-
 able to be oxidized.   In .fact, WAO often produces  biodegradable  substances
 from refractory material.   For economic  reasons,  it  is  recommended  that WAO
 systems be  designed to  remove  no more than 80% of the organics.   The optimum
 effluent  is one  that has  a 'COD/BOD  ratio of  unity, i.e.,  the  chemically
 oxidizable  material  is also biologically oxidizable.  Biological  oxidation
 can  be used  as  a  post treatment  (Water  Purification  Associates,  Decem-
 ber 1975;  Wilhelmi and Knopp, August 1979).

      The  WAO  procedure  is  normally  used for  high  strength  wastes  because
 costs scale with  the  volume of  water to  be treated.   The  energy  needs for
 WAO  often  can  be supplied  by heat released  in  the process  itself  if the
 wastewater has a high  concentration of reactive material.   It is  an  expensive
 process and would  be considered only for  high strength wastes not amenable  to
 other treatments,  such as solvent extraction.

      Chemical  oxidation.    In  this  process,  oxidation  of   the  organics  is
 caused by  adding  oxidizing agents  to  the  wastewaters.    The oxidants  are
 usually comprised of  ozone,  peroxides,   chlorine,  chlorates,  etc.   These
 chemicals  are  nonselective;  that is, they  oxidize  total  organic carbon  as
 well   as   some  inorganics.   The  oxidation  may  be  carried out at  ambient
 temperature, which is an  advantage.   Formation of obnoxious wastes  is likely
 with chlorinated  oxidants.   Explosion  is  also  a  possibility  under  uncon-
 trolled conditions.

      Thermal oxidation.    The  wastewater   is evaporated  and  the  dissolved
 organics   are  simultaneously combusted by directly  firing  burners  that  are
•submerged  under the wastewater.   Organic  nitrogen and  sulfur  compounds  will
 convert to NOx and S02,  which  is a disadvantage.   Additional waste  gases may
 form if the fuel  combustion is incomplete.   Heat transfer  within the waste-
 water  is  efficient;  however,   due  to  the  presence  of  a   large  amount  of


                                      271

-------
 noncondensable combustion gases, waste heat recovery from the overhead vapors
 may  not  be  practical.   Energy  requirements  can  be  reduced  by  using  a
 preconcentrated wastewater.

      Reverse osmosis.   In  addition  to  removing  inorganics,  this  process
 removes  organics  to a  certain  extent,  particularly  if  the organics  are
 ionized.  Tests on in situ retort waters have shown that, at a high pH, about
 95% of  the organics  are  removed.   Modern polyamide thin  film membranes are
 available  for high  pH  operation,  but  additional  data on  membrane  fouling
 characteristics  with retort  waters  are required.   The concentrate  stream
 produced requires  treatment,  possibly by WAO (Water Purification Associates,
 December 1975; Hicks and Liang, January 1981).                  '

      Ultrafi1trati on.   In  addition  to  separation of oils  and  suspended
 particles,   ultrafiltration   will   also   separate  large  organic  molecules
 (MWt s 1,000).  It is unlikely that ultrafiltration will be incorporated into
 a treatment  train for the  removal  of large organic molecules, as  these are
 not a  significant  fraction  of  total organics  in retort waters.   However,
 ultrafiltration may  be used for emulsified oil  separation and, in that case,
 would serve  as a  useful  pretreatment to RO  (Water Purification  Associates,
 December 1975).

      Carbon adsorption.   This  technology  is  used to remove organic materials
 from sewage  and  industrial  water,  as well  as  taste  and odor  from  drinking
 water.    It  is usually  used  in  conjunction with  biological  treatment  as  a
 pretreatment  or   polishing   treatment  (Cheremisinoff   and  Ellerbusch, 1978;
 Water  Purification  .Associates,  December 1975).    Laboratory  results  from
 combined carbon adsorption  and biological  treatment of  modified,  in  situ oil
 shale retort water  indicate  that  up to 85% removal of dissolved organics can
 be achieved compared to  approximately 50% removal  with biological  treatment
 alone (Jones,  Sakaji and  Daughton,  August 1982).

      Activated carbon is produced  by charring wood or  coal  at high  tempera-
 tures.   Charring  temperature  is the  main factor  determining  the adsorption
 characteristics of granular  or powdered-activated carbon.

      Carbon must  be regenerated when  it is exhausted.  The  regeneration  is
 accomplished by  passing  the  carbon  through a furnace at high  temperature,
 usually  around 800-1,000°C,  with restricted  oxidation  to remove the  adsorbed
'layer  on the  carbon.  The  quality  of carbon after regeneration  is  slightly
 lower  than the virgin carbon,  and  small  quantities of virgin  carbon  must  be
 added  to retain the required activity.                           :

      Activated carbon has  ion  exchange groups and can  be used to remove metal
 ions;  from water.    It has  been found that, under  proper conditions  of pH and
 oxidation,  some metal ions-are adsorbed very strongly.           :

      Regeneration costs are a significant  part  of overall  treatment  costs,
 making  the process  uneconomical for  high strength wastes,  for which  frequent
 regeneration  is  required.   Regeneration also is  not  attractive for  small
 units.   Energy costs for running  an  activated  carbon  wastewater treatment
 plant  are  small,  not considering  regeneration,  and are proportional  to the

                                      272

-------
pressure  drop  across  the activated  carbon  contactor.   Fouling  in carbon
adsorption  units  is  reduced if the influent stream is adequately pretreated.

     Resin adsorption.  Resin adsorption is a  physical process for removal of
organic materials.   Normally,  it  is  considered  as  a polishing  step, after
bulk organic  removal  in upstream wastewater treatment steps, but may  be used
on waters  having  higher loadings than would be used for carbon.  Also, it is
useful for removal of specific  toxic materials and phenol.

     The  polymer  (resin)  surface  can  be  made  hydrophobic  or ;hydrophilic.
Activated groups can be introduced to increase selectivity.  Regeneration can
be accomplished by  washing with methanol, weak acid or weak base.  Steam can
be used to vaporize adsorbed materials.

     Adsorption on processed shale.   This   method   has   been  proposed  for
organics  control   in retort  waters  at  oil  shale  plants.   In   studies  at
Lawrence  Berkeley  Laboratory,  processed  shale  from  the  Lurgi,   Paraho,
TOSCO II,   and three  simulated  in  situ processes  were contacted  with  four
separate  simulated  in  situ  retort waters  in  batch and  continuous  (column)
systems (Fox,  Jackson  and  Sakaji,  1980).   These studies  indicated that the
processed shale reduces the inorganic carbon by 50-98%, the organic carbon by
7-73%, and  elevates the  pH from  initial  levels  of 8-9 to a  final  level  of
10-11.  An  advantage  of the process is that the increase in pH would  facili-
tate downstream ammonia stripping and would reduce the loading on downstream
organic removal steps.

     Freezing.   As   previously  discussed,  freezing  also  removes  dissolved
organics.    One advantage  of  freezing  over  evaporation  processes  is  that
volatile  organics  are  removed  as  well.   This  process has yet  to be  applied
commercially   (Barduhn,  September 1967;   Water   Purification ,  Associates,
December 1975).

     Solvent extraction.   When  wastewater  is contacted  with  a  sparingly
soluble  immiscible  organic  solvent,  the  dissolved  organic  contaminants
partition ,themselves  between  the  aqueous  and organic  phases according  to
their relative  solubility in  each.   The organic phase is  separated and the
dissolved contaminants  removed in  a  distillation step.   Alternatively,  the
solvent and dissolved  organics may be  incinerated.   Solvent  extraction  is
most economical for  high  strength wastes because costs scale with the volume
of water  to  be treated  and  are  relatively  independent of  the  amount  of
substances removed.   Unfortunately, effective  solvents for the wide range of
organics  present in retort water have not been  found,  and it appears unlikely
that  solvent  extraction  will   be  useful in retort  water  treatment  (Hicks,
et al.,  June 1979).

     Stripping.  Volatile organics are  removed  along  with ammonia  and  the
acid gases  in  .a  stripping column or other  thermal  evaporative process.   The
amount of  organics  removed depends essentially on their  volatility relative
to water.  Organics in retort water are relatively nonvolatile and  indications
are  that  less  than  20% will  be removed  in  a column  stripping  99%  of  the
ammonia.   Organics in gas  condensates,  such as the TOSCO  II  foul  water,  are
significantly more volatile,  and bench-scale tests  have shown that up to 85%


                                     273

-------
of  the organics  are  removed along with  the ammonia.   The volatile  organics
may  then "be  incinerated,  along with  the  other  stripped gases,  or may  be
adsorbed  from  the  gas  stream  prior to  ammonia recovery  (Hicks and  Liang,
January 1981).  •

     Cooling tower.   The cooling tower may  be  regarded as a water treatment
system.   As such,  its  main function is  to  concentrate the dissolved  salts,
which may then  be removed at lower cost in a sidestream or  blowdqwn treatment
stage.   When using process wastewaters  as cooling  tower makeup,  upstream
removal  of  ammonia and  organics need not be as  efficient (and  therefore  as
expensive)  as  when the  wastewater is discharged.   It has been  demonstrated
that  refinery  phenolic  wastewaters  can  be  used in  a  cooling tower  and that
bio-oxidation   of   phenol  will  occur  with  very  high  efficiencies  (Hart,
June 11,  1973).   The conditions  necessary  for  successful  bio-oxidation are
low  sulfide (below 2 ppm)  and  small  variations in  p'H (between 7.8  to 8.3).
Chlorination  is used to prevent biological  growth.   Corrosion pf steel has
been  low.   Ammonia will  not  concentrate  in a  cooling  tower, ;but  it will
vaporize with the water.                                         ;

     Solar evaporation.   Solar radiation  incident upon  the  surface of an open
evaporation pond  is used as the energy source.   Large, lined, Shallow ponds
are  feasible  for  this  application.   The  rate of evaporation  depends   on
humidity, wind  velocity  and solar energy absorbed.  Dyes may be ;added to the
wastewater  to increase  the energy absorption, with  a  consequent increase  in
the rate of evaporation.  Land is a major cost, and  problems related  to final
disposition of  the concentrated  wastes  may  arise.  Biological  and  slow air
oxidation  of  the  organics  may  occur.   Volatile and  odoriferous components
must be removed from the wastewater prior to its evaporation.

     Disposal and containment.   Wastewater can be "controlled" with a minimum
of treatment by some  disposal  or containment options.   These options include
processed shale wetting as  part of  the  disposal  procedure.   The water and
contaminants  are either "cemented"   or  adsorbed  into the processed shale.
Provision of  an  impermeable  lining  under the  shale  pile  can prevent water
from percolating  through to the ground if the shale dpes not cement.    Water
used for  processed shale  wetting should not contain   any  volatu'les.  Since
water  used  for  revegetation  and  leaching  of processed  shale  piles  will
contribute to runoff, it may, have to be  of  considerably higher quality than
that used for moistening.

     Wastewater  may be  injected underground  (deep well   injection),  as   in
disposal  of  some  oil   well  brine wastes   (Mercer,  Campbell   and Wakayima,
May 1979).    However,  costs for  underground  injection  may  be' significant
because  deep  wells  are required  to prevent contamination  of ;upper  level
aquifers.    Legal  and  environmental  problems  associated  with  underground
injection have  not  been  clarified.   Reinjection of  mine  drainage waters may
be a possibility -for  disposal  of this stream when  excesses exist.   Geologic
and hydrologic effects may require evaluation.
                                     274

-------
      Control Technologies Analyzed--

      A  major  stream requiring  control  of  dissolved  organics  i.s  foul  water
 (stream 29).  Volatile  organics are  already removed from  the  foul  water by
 steam stripping, but  the nonvolatile organic components  may  still  remain in
 the  stripped  foul  water  (stream 38).   In  addition,  some  organics  from the
 foul water  stripper  overhead and sour water  may  be held down in the ammonia
 fractionator of  the  ammonia recovery (e.g.,  Phosam-W)  unit.   These organics
 are bled down and combined with the stripped foul  water.

      Biological   oxidation,  suggested  as  a possible  wastewater  treatment
 technology  by Colony  (Colony Development Operation,  1974), was examined for
 the  removal  of  bulk organics  in the combined process  waters.  ,It  is appli-
 cable only to biologically degradable organic matter (assumed to:be about 50%
 of the  total organics  in the foul water);  therefore,  only a partial control
 is expected from the  process.   Biological oxidation of oil shale wastewaters
 ha$ been studied,  but  it is unclear whether  the  treatment is necessary when
 the  water  is   used   for  processed  shale  moisturizing  (Hicks  and  Wei,
 December 1980).    The  design  basis  and  cost  information  for  biological
 oxidation are presented in  Table  5.2-15,  and a  cost  curve  for  the process
 when applied specifically to the TOSCO II stripped foul  water is presented in
 Figure 5.2-14.   The  description and  material  balance  for  the  treatment are
 given in Sections 3.3.12 and 4.2.8, respectively.

      Other Control  Technologies Analyzed—                      :
                                               • •                  i
      If the use of wastewaters  with high organics  loading  is not acceptable
 for processed shale moisturizing or reuse in the plant,  additional  organics
 removal  efficiency can  be  achieved by several technologies,  such as reverse
 osmosis, vapor compression  evaporation,  carbon  adsorption and wet air oxida-
 tion.   Again,  these technologies  have not been proposed  by Colony,  but they
'were analyzed based  on  their  potential  for application  in oil  shale waste-
 water treatment.

      Reverse osmosis (RO)  is a  useful technology  in that it affords  simulta-
 neous removal  of the dissolved  organics and inorganics.  With  this  technol-
 ogy,  the wastewater is  forced  through a semipermeable  membrane which allows
 the water to pass  through  but  rejects the dissolved  matter,  especially that
 which is  highly ionized.   At  optimum pH,  up  to  95%  of  the organics  and
 inorganics  can be  rejected.  The  permeate  is usually  a fairly1  clean  water
 that is  suitable  for high  quality water needs.   Reverse osmosis of in situ
 retort water has been successfully demonstrated  on  a bench scale  (Hicks and.
 Liang,  January 1981).    A specific application  of the  RO technology to  the
 TOSCO II foul  water is  illustrated in Figure 5.2-15; the estimated  composi-
 tions of  the  feedj  permeate,   and concentrate  are  given  in  Table 5.2-16;
 design and  cost  data for  the  RO  unit  are  presented in  Table 5.2-17;  and  a
 cost curve  for the  treatment is  given in Figure  5.2-16.

      Vapor   compression   evaporation  (VCE)   also   removes  the  nonvolatile
 organics and inorganics from the  wastewaters.   A  majority of the  water  is
 evaporated  along with the volatile  components.  The  vapors are then  heated  by
 mechanical  compression and  used  indirectly to heat the wastewater.  Upon heat


                                      275

-------
           TABLE 5.2-15.  DESIGN AND COST OF BIOLOGICAL OXIDATION
                           OF STRIPPED FOUL WATER
Item                                    Un.it              .    Quint ity

Stripped Foul Water                      gpm                      468
   Flow Rate

Organic Loading

   TOC                                  mg/1                    1,680
   COD                                  mg/1                    5,890
   BOD                                  mg/1                    2,940

Fixed Capital Cost                      $103

   Covered basin (154,000 ft3)                                  1,130
   Mixers                                                         130
   Clarifiers   .                                                  130
   Filter                                                        '120
   Oxygen plant (1,000 Ib/hr)                                     170
   Contingency and contractor fee           -                     386
      TOTAL                                                     2,066

Direct Annual Operating Cost            $103

   Maintenance @ 4%a                                              67
   Labor, 24 hr/day @ $30/hr                                     :237
   Electricity @ 3
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              rCH
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                                                                      TO CARBON
                                                                      POLISHING
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IDENTITY
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gpm
TEMPERATURE,0 F
PRESSURE, psig
STRIPPED
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468
100
AM8
RO PERMEATE
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400
110
AMB
RO CONCENTRATE
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68
110
• AMB
COOLING WATER

500
80
AMB
SOURCE- WPA
              FIGURE 5.2-15 REVERSE OSMOSIS PROCESS FLOW SCHEME

                                    278

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          TABLE 5.2-17.   DESIGN AND COST OF REVERSE OSMOSIS TREATMENT
                            OF STRIPPED  FOUL WATER
 Item                                              Unit        .   . Quantity

 Stripped  Foul  Water  Flow Rate                      gpm               468

 Permeate  Flow  (85% recovery)                       gpm               400

 Low Pressure (500 psi)  System                                    :
   No.  of membrane elements (UOP, TFC 8,600  PA)    —                 138
   No.  of pressure vessels                         —                  32

 High  Pressure  (800 psi)  System                  ,
   No.  of membrane elements (Film Tec)             —                  66
   No.  of pressure vessels                         —                  11

 Fixed Capital  Cost                                $103             1,686

 Direct  Annual  Operating  Cost                      $103

   Maintenance @ 4%*                                                  55
   Labor, 12 hr/day @ $30/hr                                         118
   Electricity @ 3$/kW-hr                                             53
   Membrane replacement  (18-month life)                              204

      TOTAL                                                          430


 * Maintenance  is based on the fixed capital cost  less contingency.

 Source:   WPA estimates based on information from  Hicks and Liang,
         January 1981.


 transfer, more water is  vaporized  and  the  compressed vapors  condense  to a
 fairly  clean water.   This operation is continued until sufficient concentra-
 tion  of  the   wastewater is  achieved.    The  quality of  the  condensate is
 generally  appropriate  for  uses  requiring clean, water.   Vapor compression
 evaporation has  proven  effective  for  oil  shale wastewaters  in bench-scale
 applications  (Wakayima,  May  1981).   A process  flow  diagram  for   the  VCE
 technology  is  presented in  Figure 5.2-17,  while  Tables 5.2-18 and 5.2-19
 contain the stream composition  data and design and cost information, respec-
 tively.   A cost  curve for the process,  based  on the specific design used in
this manual,  is presented in Figure 5.2-18.                      !

     The permeate from  RO or  the condensate from VCE may still contain some
organics—the   low molecular weight, unionized compounds  in  the former  case
and the volatile,  steam  strippable compounds in the latter  case.   Further
organics polishing can  be achieved  by  adsorption  on  activated  carbon.   With
this technology,  the  wastewater is allowed to pass through a bed of activated


                                     280

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FROM STEAM
STRIPPING
                                   EVAPORATOR
                                                     CONCENTRATED

                                                     TO WET AIR
                                                     OXIDATION
                                                     CONOENSATE
TO CARBON
POLISHING
STREAM
IDENTITY
FLOW RATE-
ID 3lb/hr
gpm
TEMPERATURE, PF
PRESSURE, psig
STRIPPED
FOUL WATER
243.9
487
132
AMB
CQNDENSATE
220.8
441
150
AMB
CONCENTRATE I
23.1
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150
AMB
   SOURCE:WPA
     FIGURE 5.2-17 VAPOR COMPRESSION EVAPORATION PROCESS FLOW SCHEME

                                282

-------






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        TABLE 5.2-19.   DESIGN AND COST OF VAPOR COMPRESSION EVAPORATION
                            OF STRIPPED FOUL WATER
 Item                                      Unit           .      Quantity

 Stripped  Foul Water  Flow Rate   ,          gpm                    487

 Condensate  Flow  (~90%  recovery)           gpm                    441

 No. of  Evaporators                        —                        2

 Nominal Capacity of  Each Evaporator       gpm                    250

 Fixed Capital Cost                      $103                  3,410

 Direct  Annual Operating  Cost            $103

   Maintenance @ 4%*                                             111
   Labor, 8 hr/day @ $30/hr                                      :79
   Electricity,  2,250  kW @ 3
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-------
        TABLE  5.2-21.   DESIGN  AND  COST OF ACTIVATED CARBON ADSORPTION
                          FOR RO  OR VCE TREATED WATER

Item
Stripped Foul Water Flow Rate
Organic Loading
TOC
COD
Organics Removed
Carbon Capacity
Hydraulic loading
Total No. of Adsorption Beds
No. of beds on line
Bed Diameter
Carbon Volume/Bed
Regeneration Period
Carbon Loss in Regeneration (10%)
Carbon Inventory in Beds
Furnace Area
Fuel Rate
Fixed Capital Cost
Direct Annual Operating Cost
Maintenance @ 4%*
Labor @ $30/hr
Fuel @ $3/106 Btu
Carbon replacement @ $1.80/lb
TOTAL
Unit
gpm
mg/1
Ib COD/hr
Ib COD/lb C
gpm/ft2
—
ft
ft3
days
Ib/day
Ib
"ft2
10s Btu/day
$103
$103


Treated
RO
400
84
252
40
.0.6.
5 ;
4
3
r
3.8 :
130
6
214
12,800
24
5.1
1,600

52
59 :
5
126
242 :
Feed
VCE
441
325
975
168
0.6
5
4
3
4.0
135
1.5
900
13,400
100
21
2,000

65
108
22
530
725

* Maintenance is based on the fixed capital cost less contingency.

Source:  WPA estimates based on information from Cheremisin-off and
         Ellerbusch, 1978.
                                     288

-------
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             1800
             1600
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                            200        400         600

                                  FLOW RATE, gprri
                                                                 280
                                                                 240
                                                                     10
                                                                      o
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                                                                 160
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                                                                 700
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SOURCE:   WPA
        FIGURE 5.2-20  COST  OF ORGANICS CONTROL  WITH CARBON ADSORPTION



                                       289

-------
 and pressures, and air  or  oxygen Is  introduced into the reactor to cause the
 oxidation  of the organics.  Only high  strength feeds are  economical  for WAO
 treatment;  therefore,  a preconcentration  of  the waste,  such as .by RO  or VCE,
 is  desirable.   A process flow  scheme for the WAO  technology  is  presented in
 Figure  5.2-21.   The composition  of  the  WAO  sludge  and the design and cost
 information  for the  process are  given  in Tables 5.2-22 and 5.2-23,  respec-
 tively, while  Figure 5.2-22 presents  a cost curve for the technology.

 5.2.5   Water Requirements

     Steam Production—

     The steam balance for the TOSCO II  plant  is presented in Table  5.2-24.
 Approximately  820,000 Ib/hr of steam are produced  by  the utility boilers,
 with approximately  70% of this steam being  used in  consumptive  applications
 such  as steam  reforming,  retort  sealing,  etc.   The  remainder  is  condensed
 upon use and returned to the boilers.   About 20% of  the feedwater makeup  is
 removed as blowdown.  The losses  from consumptive  steam  uses and  blowdown  are
 compensated  with clarified  and  softened river water.   Estimated water  quality
 parameters for the boiler feedwater are indicated  in  Table  5.2-25.

     Cooling Water—

     Typical cooling  water requirements  for  the three TOSCO II  .case  studies
 are  summarized in Table 5.2-26.   Treated river  water could be, used as the
 makeup  to  the cooling  tower.   The water  quality parameters for the  cooling
 water are  indicated in  Table  5.2-27.  The cycles  of concentration are kept
 low,  at about  2; the   relatively  large  amount  of blowdown is  used,  after
 equalization with  other streams,   for processed  shale quenching  and moisten-
 ing.   Sulfuric  acid   is added  to  the  makeup  water to  control   carbonate
 scaling.

     Processed Shale Moistening—

     The hot processed  shale   leaving  the TOSCO II  retorting area must be
 cooled  and  moistened with  water   in  the  processed  shale moisturizing  mixer
 before  being sent to  the  disposal area.   The  hot  shale is first  quenched,
 resulting  in evaporation  of approximately 500  gpm of  water.   The quenched
 shale is then  moisturized,  with  approximately  1,640 gpm of composite  water
 from the equalization basin, to a final  moisture content  of approximately 14%
 to facilitate compaction and stabilization.  The optimum moisture content and
 the extent  to  which wastewaters  should  be treated have  not yet been deter-
mined.   The  blowdowns  from  the  cooling tower,  boilers,  and clarifiers  could
be used for quenching and moistening.   These water streams should not contain
volatile material  which would  be released upon contact  with  the hot shale.
Table 5.2-28 indicates  the water  flow  rates (gpm)  for  quenching  and  mois-
turizing.

     Processed Shale Disposal—

  .At the  disposal   area, water is needed for  dust  suppression  and for
revegetation.  Table  5.2-28 also  includes the  water requirements  for these


                                     290

-------
  •  41R
X
y
CONCENTRATE.
FROM RO OR
VCE
                  AIR COMPRESSOR
                        -€7
          HIGH PRESSURE PUMP
                                                   REACTOR
                               HEAT EXCHANGER
                                                                GAS
                                                                SEPARATOR
                                                                           EXHAUST
                                                                            GASES
                                                                           OXIDIZED   \
                                                                           CONCENTRATE /
                                                                           TO PROCESSED
                                                                           SHALE
                                                                           MOISTURIZING
                                                                           OR SOLAR POND
STREAM
IDENTITY
RO FLOW RATE:
!03lb/hr
gpm
VCE FLOW RATE'
I03lb/hf
gpm
TEMPERATURE, °F
PRESSURE, psig
CONCENTRATE

34.3
68

23.1
46
110-150
AMB
OXIDIZED
CONCENTRATE

33.9
68 ,

22.2
45
160
AMB
AIR

5.1


4.5

AMB
AMB
EXHAUST
GAS

5.5

.
5.3

160
AMB
        SOURCE: WPA
                    FIGURE 5.2-21 WET AIR OXIDATION PROCESS FLOW SCHEME

                                         291

-------













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292

-------
           TABLE 5.2-23.  DESIGN AND COST OF WET AIR OXIDATION OF
                       RO AND VCE CONCENTRATE STREAMS

Item
Concentrate Feed Rate
Organic Concentration: TOC
Reactor Residence Time
Reactor Pressure
Oxygen Demand
Air Compressor Rating
Fixed Capital Cost
Direct Annual Operating Cost
Maintenance @ 4%*
Labor, 12 hr/day @ $30/hr
Electricity @ 3$/kW-hr
TOTAL
Unit
gpm
mg/1
hr
psi
Ib/hr
Ib/hr
$103
$103


Concentrated
RO
68
10,750
1
900
1, ISO-
'S, 100
5,360

174
118
79
371
Feed
VCE '
46
13,900
1
900
990
4,500
4,060

132
118
63
' 313
* Maintenance is based on the fixed capital cost less contingency.

Source:   WPA estimates based on information from Wilhelmi and Knopp,
         August 1979.                    .   .
                                     293

-------
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                                   294

-------
      TABLE 5,2-24,  STEAM PRODUCTION, USES AND BOILER FEEDWATER NEEDS

Parameter
Steam Production
Consumptive Steam Uses
Pyrolysis
Steam reforming
Miscellaneous
TOTAL
Nonconsumptive Steam Uses
Ami ne/Claus/Well man- Lord
Stretford
Ammonia recovery plant
Foul water stripper
TOTAL
Steam Credit
,. Claus
Ammonia recovery plant
TOTAL
Net Steam Circulated
Feedwater Makeup Requi rements
Boiler Slowdown
Softner Regeneration Waste
Consumptive Steam Uses
TOTAL FEEDWATER MAKEUP

Unit A
gpm
390
448
^282
1,120
gpm
242
312
65 '
619
gpm
76
20
: 96
gpm 1,643
• . . •
gpm 280
gpm 122
gpm 1,120
1,522
Case Studies
B
<
390
448
282
- 1,120

242
312
65 J
619 !

76 1
20
96
1,643
280 i
122 ;
1..120
1,522

C

390
448
282
1,120

38
312
65
415

20
20
1,515
280
122
1,120
1,522
.
Source:  WPA estimates.
                                     295

-------
        TABLE 5.2-25.  WATER QUALITY PARAMETERS FOR BOILER FEEDWATER

Parameter
TDS, mg/1
Total AT kal i ni ty , mg/1 GaC03
Total Hardness, mg/1 CaC03
Iron, mg/1 Fe
Copper, mg/1 Cu
Silica, mg/1 Si02
Specific Conductance, |jmhos/cm
Low Pressure
0-300 psi
2,300*
470*
0.3
0.1
0.05
100*
4,700*
High Pressure
600-750 psi
1,300*
! 270*
0.2
0.025
0.02
20*
2,700*

* For a boiler concentration factor of 1.5.

Source:  WPA estimates based on data from Krisher, August 28, 1978.




               TABLE 5.2-26.  PLANT COOLING WATER REQUIREMENTS   :

Water Use
Evaporation and Drift
Stretford Cooling
TOTAL LOSSES
Slowdown
TOTAL COOLING TOWER MAKEUP
Cycles of Concentration
Unit
gpm
gpm
gpm
'
Case
A, B
1,530
1
1,530
1,530
3,060
2
Studies
C
; . 1,530
116
1,646
1,646
3,292
2

Sources:   WPA estimates based on information from Colony Development
          Operation, 1974.                ,
                                     296

-------
    TABLE 5.2-27.  WATER QUALITY PARAMETERS FOR COOLING TOWER RECIRCULATIOfT

Parameter
Langelier Saturation Index
Ryznar Stability Index
pH '•
Calcium, mg/1 as CaC03
Total Iron, mg/1
Manganese, mg/1
Copper, mg/1
Aluminum, mg/1
Sulfide, mg/1
Silica, mg/1
(Ca)-(S04), product
IDS,, mg/1
.Conductivity, micromhos/cm3
Suspended Solids, mg/1
TOC mg/1
NH3. mg/1
CN~ mg/1
Limits
Minimum Maximum
+0.5 +1.5.
+6.5 +7.5
6.0 8.0
20-50 300
400
0.5
. 0.5
0.08
1
5
150
100
500,000
2,500
4,000
100-150
600
100
' •' 5 ."
Remarks
Nonchromate treatment
Nonehromate treatment

Nonchromate treatment
Chromate treatment





For pH < 7.5
For pH > 7.5
Both calcium and
sulfate expressed
as mg/1 CaC03





.. • .
a Concentration in makeup obtained by dividing values above by cycles of
  concentration.

b The limits for the Langelier Saturation Index (an indication of GaC03
  saturation) presume the presence of precipitation inhibitors in nonchromate
  treatment programs,  In the absence of such additives, the limits would be
  reduced to 0 and 0.5.

Source:   WPA estimates based on data from Hart, June 11, 1973.

                                     297

-------
       TABLE  5,2-28.  WATER  REQUIREMENTS  FOR PROCESSED  SHALE  DISPOSAL
                               AND DUST  CONTROL
                                Water  Required      Shale  Rate     Water  Rate
Water Use                       Mass % of  Shale     103  Ib/hr          gpm

Processed Shale Disposal

  Quenching and Moistening           18.2             4,514*          1,640
  Processed Shale Dust Control         2.9             4,514            260

  Revegetation                         4.1             4,514            370
Raw Shale Dust Control
At Mine
Crushing
At Plant
3.2
1. 4
1.0
5,465
5,465
5,465
367
153
110

* Dry processed shale rate.

Source:  WPA estimates.


needs.   The water required  for  dust control is 2.9  mass  percent of the dry
processed  shale  rate,   and   the  requirement  for  revegetation  is  4.1 mass
percent.  Any  water  used in  revegetation at the disposal area should be of a
quality acceptable for agricultural  use.               .....'

     Dust Control —

     The water requirements  for mining, crushing,  and fugitive ,dust control
are  also  summarized in  Table 5.2-28.   These requirements  are  given as flow
rates  (gpm),   as  well  as  mass  percents of  the  raw shale  rate.   The mass
percents are  3.2%, 1.4%,  and 1,0%  for mining, crushing,  and  fugitive dust
control, respectively.

     Water  used  in confined mining operations should be  low in volatile or
toxic  materials  because  mining personnel  will be directly exposed  to it.
Also, the water  should  contain low amounts of suspended and dissolved solids
to reduce clogging and  scaling in  spray nozzles.   The water used in mining,
crushing, and fugitive dust  control operations cannot be recovered.

     Miscellaneous Requirements—

     These  include potable  and  sanitary needs, as well.as service  and fire
water, requirements.   Table  5.2-29  summarizes  these  water  requirements  in
terms  of makeup,  discharge   and  overall water consumption.   Any treatment
necessary for  these waters  is standard practice and  not a pollution control
activity and, therefore,  is  not discussed in depth.


                                     298

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 5.3-  SOLID WASTE MANAGEMENT

      The TOSCO II processing facility will  be a source of large quantities of
 plant wastes which will  require disposal.   Table 5.3-1  indicates  the makeup
 of the waste material  that will be discarded from the plant over a period of
 20 years (project life).   Sections 3  and 4 give information about the origin
 and composition of these streams.

      The waste  material disposal  approach  and the  practices 'used  in  the
 disposal  can  have  a  long-lasting  impact on the atmosphere and  hydrology of
 the area as well  as  on the local aesthetics  and  habitat.   The primary areas
 of environmental  concern in this regard are:

      •    Surface Hydrology

      *    Subsurface  Hydrology

      *    Surface Stabilization
      *    Hazardous Wastes.

      This   section  briefly  describes  the  disposal  approaches  that  may  be
 applicable  to  the wastes  produced  from  an  aboveground retorting facility
 (e.g., TOSCO  II)  involving  underground mining  of the  oil  shale.   In addition,
 a  discussion  of control  technologies  available  to  mitigate the  potential
 impacts  in  the  areas  mentioned above .is  presented.   The  applicability  of
 these technologies  should   be  determined  on  a  site-specific,  case-by-case
 basis.   Specific  information :for the  facilities  involving open  pit  mining  and
 aboveground retorting can be found  in  the Lurgi-Open  Pit  PCTM,  while specific
 information for  the  combined Modified  In  Situ-aboveground  reto.rting  opera-
 tions can be  found in the MIS-Lurgi PCTM.

 5.3.1 Disposal Approaches

      The following discussion applies  to the basic methods for  handling  solid
 wastes  produced  by  the TOSCO  II  process.   Generally,  the  mining  method,
 geography  and hydrology of  the  area,  and the waste characteristics  influence
 the  applicability of  a disposal  approach.  The  key features of each approach
 are  summarized  in  Table 5.3-2.   A discussion  of the  control  technologies
 applicable  to 'these disposal alternatives is presented later in this section.

      Landfills—

     A landfill  basically entails placing the waste  material  as a  compacted
 fill  in  a  suitable  location.   The wastes  from the  processing facility  are
 transported to  the disposal site by  conveyors or trucks and  then hauled to
 the  active  portion of  the   landfill.    Usually,  the  solids  are laid down in
 lifts  of 9-18  inches  and  compacted  to  a   suitable  in-place  density.    The
 compacted  fill  may  be  built  with  a  proper slope to  a vertical  height,of
40-50 feet  and  then flattened,  or  benched, to  provide  a passageway for  the
disposal  equipment and to facilitate runoff collection.  The overall landfill
can be constructed gradually in. this fashion, using a multiple-bench arrange-
ment.
                                     300

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         TABLE 5.3-1.  MAJOR WASTES PRODUCED OVER A PERIOD OF 20 ;YEARS
Stream
Number
12
21
22
23
27
38
86
103
133
148
149
168
169
175
177
178
94, 109,
122
-•- .
—
-•<•
'-•-
TOTAL
Stream Description
Raw Shale Runoff and Leachate
Raw Shale Sludge - Preheat System
Processed Shale Sludge - Ball
Elutriator
Processed Shale Sludge -
Moisturizer
Processed Shale
Stripped Foul Water
Compression Condensate -
Wellman-Lord Unit
Coke
Stripped Sour Water Purge Stream
Revegetation Water
Dust Suppression Water
Boiler Slowdown
Boiler Feedwater Treatment
Concentrate
Cooling Tower Slowdown
Storm Runoff
Processed Shale Leachate
Spent Catalysts
Treated Sanitary Water
Sanitary Water Treatment Sludge
Service and Fire Water Runoff
Source Water Clarifier Sludge
Trash, Construction Debris, etc.
Material Quantity
Quantity, as a Percent of
10s tons Total Waste Quantity
N.D.*
11. 31
0.85
0.57
350.84
18,49
1.73
5.26
0.75
14.59
9.70
11.04
4 .'81
60.31
4.34
N.D.
0.005
0.55
N.D,
0.63
2.37
N.D.
498.15
, N.D.
2.27
0.17
:
0.11
70.43
3.71
6.35
1.06
0.15
.2.93
1,95
2.22
0.97
12.11
0.87
N.D.
0.001
0.11
N.D.
0.13
0.48
N.D.
99.93
* N..D. = Not determined.                                         ;

Source:  DRI estimates based on information from Colony  Development
         Operation, 1974, and U.S. .001, 1977.
                                     301

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      Depending upon the  geography  of the disposal site,  the  landfill  may be
 built on a  level  or nearly level  surface,  in the head of a valley, or across
 a valley.  The applicable  control  technologies will  vary  somewhat with site
 topography but still will  be designed to protect  the  surface and subsurface
 waters.   Applicable  control  technologies include  runon  and  runoff catchment
 ponds,  embankments  and diversion  systems,  liners and covers,  and revegeta-
 tion.    Provision  for  structural  stability  of  the  fill  is  also a  major
 consideration.

      A  surface landfill  of  some  type will  need to  be  included  in most oil
 shale  developments.    This  results  from   the  shale  undergoing  a  volume
 expansion upon mining, crushing, and processing, which  precludes  all  of the
 shale being returned to the mine.

      The head-of-valley disposal approach  for the TOSCO  II processing wastes
 has  been  proposed  by  the  Colony  Development  Operation (March 1980)  and  a
 permit   has  been  granted   by  the  Colorado  Mined  Land  Reclamation  Board
 (October 23,  1980).   A  description  of the  permitted   landfill   design  is
 presented in Section 3  of this manual..

      Underground Mine Backfill —

      In  this disposal approach, the  waste  material is  placed  in, the inactive
 portion  of  the  underground mine  (e.g.,  a  room-and-pillar mine),  while pro-
 duction  continues in  other parts  of the mine.   This approach  is  attractive
 from several viewpoints.   By  returning  the wastes  to the mine,  the size of  a
 surface  landfill would  be greatly reduced.   The potential for  mine subsidence
 would be .diminished,  and revegetation  would not  be necessary.   Backfilling
 the  mine may enhance resource recovery by increasing  the  amount  of shale that
 can  be  mined  safely.   Disadvantages  include possible   release of volatiles
 underground in the workplace  and possible groundwater contamination.

      The major considerations  in backfilling involve  developing  logistics for
 carrying out  simultaneous  mining  and  disposal operations  while  providing
 protection  for  workers and the  groundwater.   For fine  processed: shales, like
 the  TOSCO II,  hydraulic  or  slurry backfilling  may  be practical.   However,
 additional  water,  above  the  moistening  needs,  would  be  required  and  a
 drainage  collection  system would be needed.   The wastes may be transported to
 the  mine  by conveyors  or  trucks,  then compacted in place, but the  space
 limitations  reduce the practicability of this approach.    Alternatively,  the
 wastes may  be backfilled  pneumatically,  but  this approach may  be, difficult to
 implement at the scale  required,

     A  study on  the above backfilling techniques has been conducted  for the
 wastes  from the Colony project (Dravo  Corp.,  1975).  The results  indicate
•that, while theoretically  80% of  the wastes  could be  returned  to  the  mine,
 only  60% of the wastes can actually  be  placed in the mine  during  the project
 life  due  to a time lag  of  5-10  years  between the  mining  and  backfilling
 operations.  It was  also  concluded  that  none  of  the placement  techniques were
 developed sufficiently  to be  applied  on  a large  scale.
                                     303

-------
     Hazardous Waste Lagoon—                         .

     A hazardous  waste lagoon  would be a  permitted facility  either on the
project site  or  off site.   It would  likely  consist of a lined pond designed
to  be suitable  for the  containment  of hazardous  wastes.   The  major con-
siderations  in  the design  of such  a pond  would  include a  runon diversion
system, an  embankment, one  or  two  impervious  bottom 1iners with a drained
sand  layer  below or between them,  a slurry wall  beneath the  embankment,  a
surface  seal   layer,   and  provisions  for  reclamation   and   revegetation
(U.S.  EPA,  September 1980).

     Once  the  lagoon   is   filled  to  its  capacity, wick  drains  could  be
installed to  facilitate evaporation,  allowing quicker consolidation  of the
sludge.  Gravel  could  also  be  added  to  aid consolidation.   An  impermeable
surface seal  may then  be  added on  top  and joined with the  bottom liner to
isolate the wastes from the surrounding environment.  The final  aspects would
include placing subsoil and topsoil  over the  seal,  followed  by revegetation
of the surface.

5.3.2  Surface Hydrology Control Technologies

     Solid waste management practices in the area of surface hydrology entail
the  handling  of  surface  waters   on  and  around  the  disposal  facility.
Specifically, surface  streams and precipitation  are prevented  from running
onto the waste pile and contaminated waters (runoff, leachate)  are kept from
mixing with the natural waters.

     The technologies  discussed below are  those  that  are  applicable  to  a
surface landfill, and  they  are  summarized in Figure 5.3-1.   The key features
of  the technologies   are  highlighted  in Table  5.3-3  and  a. more  detailed
description with cost data is presented in the text.

     Runon Diversion System—

     A runon  diversion  system  will  generally be  needed with  any  surface
landfill  to  prevent surface  water from flowing onto the waste  material and
becoming contaminated  or  causing  erosion.   The system may  include ditches,
lined  channels,  conduits,  and  embankments  arranged to  direct the  flow of
surface water around or away from  the waste material, and energy dissipators
to moderate the impact of the flow.

     The complexity  and extent of the system will  vary widely based-on the
amount of water  to  be  diverted  and  the  arrangement of  the  site.   For a fill
on  a  relatively  level  site, runon  diversion  may  require only a  system of
channels  and  small  embankments to deflect surface flow away from the land-
fill.   In  the case of a head-of-valley  fill  or a  cross-valley,  fill, runon
diversion might  include  an embankment  dam  to  retain  peak  flows  from the
design storm until they can be passed through a conduit beneath  or around the
fill..  Alternatively,  the  system  may consist of a conduit or  channel large
enough to  pass  the design  flow without  an  embankment  (without  retention).
                                     304

-------
    SURFACE
    HYDROLOGY
    CONTROL
    TECHNOLOGIES
                           RUNON
                         DIVERSION
                          SYSTEM
  RUNOFF
COLLECTION
  SYSTEM
                         RUNOFF/LEACHATE
                         COLLECTION PONDS
                    I—  WITH RETENTION


                     •  NO RETENTION
SOURCE' SWEC
    FIGURE 5.3-1  SURFACE  HYDROLOGY CONTROL TECHNOLOGIES

                           ;  305

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      The costs for three  runon  diversion systems were estimated and they are
 plotted in  Figure  5.3-2.   Examples 1  and 2 consisted of runon  retention  in
 combination with continuous  controlled release.   Example 3 was  designed for
 no  retention,  which  necessitated  a  large  channel  and  extensive  use  of
 reinforced concrete energy dissipators;  the higher  cost  associated with such
 a system is illustrated  in the figure.

      Examples  1 and 2  also consisted of an earth  embankment  for the retention
 of runon and, an embedded  conduit for controlled release.   Channeling  of the
 controlled release  flow around  the  waste pile in Example 1 was  accomplished
 with a  lined  canal,  while  Example  2  utilized an  extension of,the  embedded
 conduit for the controlled release.                              ;

      The cost  of a runon  diversion  system will be influenced by:  the size  of
 the  drainage area  and topography which affect the runon rates^  retentions,
 and   embankment  material  quantities;   the  size,  length,  and  complexity  of
 controlled release  structures  and channeling  systems; and  the ,need for and
 extent  of energy dissipators and/or drop structures.   For example,  the runon
 from a  site with a large  drainage area  in  a  gently sloping topography could
 be diverted quite  efficiently by an unlined  canal  or channel;  another  site
 with small runoff rates,  but  highly  erodible  steep  topography,  may  necessi-
 tate cost-intensive  lined channels,  flumes  or  conduits,   as  well  as  drop
 structures or  energy  dissipators.   In  summary,  the cost of  this system  is
 highly  site-specific.

      Runoff Collection System—

      A  runoff  collection  system usually  consists  of  a  system of channels,
 ditches,   and   conduits  arranged  to  prevent  the  surface  water  that has
 contacted  the  waste material from.leaving the  site.  Another purpose of  this
 system  is  to drain the surface water from the wastes to limit the erosion and
 infiltration potential.   Collected water may  also  be used to meet process
 needs.

      The  basic  elements  of this system  are  backsloped benches  on  the face  of
 the  landfill and  a means of  collecting  the  water  from the  fill surface.
 Generally,  half-round  pipes, impervious  membranes,  or highly  compacted  soil
 or wastes are used to line ditches  which  collect the  runoff  frbm the bench
 and  the segment of  the  landfill  slope  above  it, as  shown  in Figures 5.3-3
 and  5.3-4.   The ditches  empty  into  central conduits  leading  to a contain-
 ment/evaporation  pond  at  the  toe of  the  landfill.    On  larger  piles  or  in
 areas  with  extensive  rainfalls,  small   embankments  on  the   crest  of  the
 landfill  or on  the  benches might be used  to retain the runoff  and thus limit
 the peak flows into the rest of the drainage system.

     A  problem  with limiting  the peak flows using embankments on the waste
pile  is that the water ponded on the landfill will have a greater tendency to
 infiltrate  the  waste  material.    This  increased  infiltration  could  have  a
 detrimental  effect  on  the  stability of  the  slope and  will  somewhat increase
 the  amount  of water which  must be handled by  the leachate collection system
 (discussed under subsurface hydrology).
                                     307

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NOTES:      '           '.'•••                    .    ,       ;

  Examples 1 & 2 include retention with embankments and continuous  controlled
  release through an embedded conduit. .

  Example 3 was designed to handle the maximum flow without  retention.

  Example 2 is  specific  to the TOSCO II case studies, except the embankment
  dam is smaller than the one proposed by Colony.              .

  See  Section 6.2.3  for details, on the  solid  waste management  cost
  methodology.
SOURCE:  SWEC
                     FIGURE 5.3-2  RUNON DIVERSION COSTS
                                     308

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      The  costs  for  a  variety  of runoff  collection  system  designs  were
 estimated  and  these  are  plotted  in  Figure 5.3-5.   Example 1  used  shaped
 benches  with   unlined   ditches  for  lateral  conveyance  and  concrete  weir
 collectors  and  corrugated metal pipe  with energy  dissipators for  vertical
 conveyance.   It also incorporated  some  temporary  retention of runoff  on  the
 waste pile  surface,  which  reduced the  necessary capacity and  cost of  the
 vertical  conveyance portion of the system.   Example 2 used split  corrugated
 metal  pipe  to line the  collection  ditches  to facilitate -lateral conveyance,
 and  concrete weir collectors and corrugated  metal pipe with energy  dissipa-
 tors  for  vertical  conveyance.    Example  3 used  the lined ditches for  lateral
 conveyance,  with  a concrete fl-ume  and  a stilling basin for vertical  convey-
 ance.

      The cost  data> as can be  seen in  the plot,  are  highly dependent on  the
 particular design,  and no  single cost curve relationship can be drawn  through
 the  data  points.   Example 1, which assumes a more modest design, defines  the
 lower boundary of  the  cost envelope,  and Example 3 defines  the  high end of
 the cost envelope,

      Runoff/Leachate Col 1ecti on Ponds—

      At the  outlet of the collection system  for surface runoff,  a structure
 is needed to contain the  collected water for reuse, treatment and discharge,
 or  for evaporation.  The  structure would consist of  an embankment across a
 former  stream  channel  to  form  a pond,  and the pond may  be lined or  unlined
 depending upon  the nature of the impounded material.   If a liner is  needed,
 it would be  protected from wave  action,  as  necessary, using rip-rap, a sand
 layer, soil  cement or similar  materials.  Since the.pond would be located at
 the base of  the landfill, it might also be used to collect the leachate from
 the fill.

     Cost data for four  examples  of  runoff/leachate collection  ponds  are
presented in Figures  5.3-6 and  5,3-7.    Figure 5.3-6 presents  the total cost
of  the embankment and  liner  as a function of  the construction  material
quantities used in each  case,  while Figure  5.3-7 isolates the  cost of the
 liner as a function of the liner material quantity only.   Examples 1, 2 and 3
utilized compacted  processed shale  as  the liner, while Example 4 used Mancos
Shale as the liner.  The  relatively high cost of  using an off-tract material
 (Example 4)   is  evident  in the   figures.   The cost  increase is incurred due to
the source development,  processing  and  hauling of Mancos Shale.   Slight cost
differences   may  be observed   between  similar  systems, and  these   can  be
attributed to  site-specific  features,  such as the arrangement and configura-
tion of the  embankments and ponds.                               :

5.3.3  Subsurface Hydrology Control  Technologies

     The  technologies   and practices  in the  area  of  subsurface  hydrology
involve the  handling  of  groundwater  seepage  under  a  landfill to  prevent
infiltration of  the pile  and the control  of  water from the pile  to prevent
contamination  of  the  groundwater.   The  technologies,  as  summarized  in
Figure 5.3-8, are  applicable to .a  surface landfill,  and their  key features
                                     311

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RUNOFF QUANTITY, ACRE-FT
                                                             400
NOTES:
  Example 1  utilizes  shaped benches as unlined  ditches  for lateral runoff
  conveyance.

  Examples 2 & 3  utilize  split corrugated  metal pipe to  line  ditches  for
  leiteral runoff conveyance.

  Examples 1 & 2 utilize  buried  corrugated  metal pipe and energy dissipators
  for vertical runoff conveyance.

  Example 3  utilizes  a concrete  flume with  stilling basin for  vertical
  runoff conveyance.

  Example 2  is specific to the TOSCO II case studies, except that Colony has
  proposed lined ditches for vertical conveyance.

  The costs indicated are cumulative for the project  life.       :

  See  Section 6.2.3  for  details  on the  solid  waste  management  cost
  methodology.
SOURCE:  SWEC
                    FIGURE 5.3-5  RUNOFF COLLECTION COSTS
                                     312

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NOTES:           :

  All Examples include cost of embankments and pond liners.

  Examples 1, 2 & 3 include pond liners constructed of processed ;shale.

  Example 4  includes  a  liner  constructed  of  Mancos Shale  (off-tract
  material); cost is increased due to processing and transport.

  Example 2  is  specific  to the TOSCO  II  case  studies,  except no liner  is
  mentioned in the Colony proposal.

  See  Section 6.2.3 for  details on  the  solid waste  management cost
  methodology.
SOURCE:   SWEC
                  FIGURE 5.3-6  RUNOFF/LEACHATE POND COSTS
                                     313

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NOTES:

  Examples 1, 2 & 3 include liners constructed of processed shale.

  Example 4  includes  a  liner  constructed of  Mancos  Shale  (off-tract
  material); cost is increased due to processing and transport.

  Example 2  is  specific to the TOSCO  II  case studies, except no  liner  is
  mentioned in the Colony proposal.

  See  Section 6.2.3  for details  on  the  solid  waste management  cost
  methodology.
SOURCE:  SWEC
               FIGURE 5.3-7  RUNOFF/LEACHATE POND LINER COSTS


                                     314

-------
 are  presented  in Table 5.3-4.   Detailed descriptions  of the  technologies,
 along with  cost  information,  are  presented below.

     Liners and  Covers—

     A  liner is  essentially  a material with  low water permeability that  is
 installed at the bottom of  a  landfill  or pond.   Its purpose  is to  prevent the
 contaminated waters  from the  wastes  from mixing  with  the groundwater. It also
 prevents groundwater from infiltrating the bottom of  the landfill.

     A cover is  also made up  of a low-permeability material  and  it is used  as
 a  surface  sealer for the landfill.   It prevents the  runoff  from infiltrating
 the  pile,  thereby  reducing   the quantity  of  the   leachate  an'd   minimizing
 stability problems.

     There  are  several  materials which can  be  considered  for the  liners and
 covers.   Probably the least  expensive material  would be compacted processed
 shale.   It  has  the  advantage of  being readily available  at  the site.   A
 similar  lining  could be made  of  processed shale or clay from off  site  if the
 quality  of   the  processed  shale  from  the site  is unsuitable;  however,  these
 options would  be relatively expensive  due to  the extra handling  and hauling
 costs.   There   is   also  a   variety   of  synthetic   liners  which  could   be
 considered.  High-density polyethylene, for  example,  would  range  upward from
 a  price  similar  to that  for the  off-site materials,  depending  upon  the
 thickness  used.   This would  make it  very  expensive for  use  in; a processed
 shale  landfill  and  it  may  have  questionable  long-term durability.  Another
 option that could be considered, particularly for a  hazardous  waste lagoon,
 is  simply  a combination  of  a  synthetic  liner  with  one of  the  other  liners
 mentioned above.

     Linings made of natural  materials will dry  and crack  if they are left
 exposed to  the weathering elements for  long periods.   Therefore,  if a pond  is
 not  expected to  remain  at  a relatively consistent level, a synthetic  liner
 might be  considered.  Hazardous waste  lagoons sometimes have  double liners;
 however, the catchment and evaporation ponds presumably  will need only one
 liner  or no liner since they  will  not contain hazardous materials.   If  a
 combination  of  two  liners  is used,  the synthetic liner may be  placed  above
 the  natural material  liner  to  prevent its  drying  and cracking.    In  cases
where a  synthetic liner is  used,  it  should  be  covered by a layer of sand or
 gravel  to  protect it from  traffic  and wave action.   Also, because of  the
weight of  the  fill  and because  the  fill  may be placed  above  an underground
mine,  the   liner  must  accommodate  a  certain  amount  of  subsidence  and
 stretching, and still  function properly.

     The  cost  of  liners  and covers  depends  on  the quantity  and  type  of
material used.    Figure 5.3-9  presents the  costs for three  separate liner and
cover  systems.    Examples 1  and  2  assumed  the use  of  highly  compacted
processed shale  for  construction  of the liners,  while  Example 3 assumed  the
use  of  Mancos  Shale.   The  compacted  processed  shale represents  the  lowest
material cost option, while  Mancos Shale is  a more expensive  natural material
since  it  has  associated  source  development,  processing and hauling  costs.
The  cost  curve  in the  figure may be  used to obtain  an "order-of-magnitude"

                                     315

-------


LINERS
AND
COVERS



                                             r— SYNTHETIC

                                                OFF-SITE
                                                NATURAL MATERIAL

                                                COMPACTED
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                                                SHALE
DUDDUnrAUC
HYDROLOGY
CONTROL
TECHNOLOGIES




LEACHATE
COLLECTION
SYSTEM

                         6ROUNDWATER
                         COLLECTION
                         SYSTEM
SOURCE' SWEC
   FIGURE  5.3-8  SUBSURFACE HYDROLOGY CONTROL TECHNOLOGIES

                             316

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 estimate  of  liner cost  utilizing  highly compacted processed  shale as  the
 construction  material.   The  estimated cost  for other liner materials  would
 fall  above this curve to  a  degree which  is  dependent  on  the source  develop-
 ment,   processing,  and  hauling  costs   associated  with  delivering   these
 materials  to  the disposal  site.                         '''.''.

      Leachate Collection System--

      The  purpose  of  a  leachate collection  system  is  to collect water  which
 infiltrates  a  landfill  and  drain  it efficiently  in  order to prevent  the
 saturation of the  landfill and contamination  of  groundwater  beneath the  waste
 pile, as well  as to facilitate handling of the leachate.

      Leachate collection  systems typically consist of  blankets, or zones, of
 highly  pervious  sand and gravel.   In  some cases this  is  augmented with
 embedded  perforated pipe  to  increase the capacity, and  it may ialso include
 collector ditches  where the system emerges onto  a broad level area.  The sand
 or  gravel  layer would be  located  just above the bottom  liner  and it may be
 wrapped  in filter  fabric  or surrounded by  carefully  graded sand filters to
 prevent  infiltration  by  the processed shale  particles.   In either case,  the
 collection system  should  be designed  so that movement  and settlement do  not
 result  in  discontinuity,  of  the  gravel  layer  or impede  drainage to  the
 collection or evaporation ponds.

      The  costs for four distinct  leachate collection  systems  were estimated
 and  these  are  presented  in  Figure 5.3-10.   In  Examples 1 and  2,  due to  the
 valley  shape  of the disposal  site, only the  drain material was  necessary  for
 the  collection system.   The  leachate in these  two cases  was  drained in  the
 runoff/1eachate  collection pond  located  downstream  from the  landfill.  In
 Example 3,  a  toe  ditch was  necessary  to collect the leachate  due to  the
 presence of  the broad valley area at  the toe of the landfill.   The ditch was
 then drained  into the common runoff/Ieachate  collection pond.  Example 4 also
 required a toe ditch which was drained into a leachate  collection pond,  while
 the  runoff  was impounded  separately in evaporation ponds  on the  waste pile
 surface.  Examples 3 and 4 required the same  drainage material  quantity.  The
 cost  difference between   the  two  examples  is  due to the  inclusion   of a
 separate collection pond in Example 4.  Data  point 5 on the figure represents
 the cost of drainage material only for Examples 3 and 4.  The cost of the  toe
 ditch may be  obtained by subtracting data point 5 from 4.

     The costs for similar  systems  should be proportional  to  the volume of
 drainage material  used, but  slight deviations may  be encountered  due to the
 site-specific conditions.

     Groundwater Collection System—

     The purpose of a groundwater collection system is  to  relieve pressure
 from the seeps and  springs beneath a landfill.  This situation  is most likely
 in the cases of cross-valley or head-of-valley landfills.   The  system will be
essentially identical to  the leachate collection system  except it  would be
below the bottom liner rather than above it.
                                     318

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                                                           16
NOTES:                                                           ;

  Examples 1 & 2 utilize 3 feet of highly compacted processed  shale  for liner
  material.                       .

  Example 3 utilizes  3 feet  of compacted Mancos  Shale (off-tract material)
  for  liner  material;  cost  of processing and hauling this  material makes
  this option more expensive than the othens.

  Example 1 is  specific to  the TOSCO II case  studies, except the  Colony
  proposal includes only a 2-foot, rather than 3-foot,  thickness.

  The costs indicated are cumulative for the project  life.

  See  Section 6.2.3  for  details  on the  solid  waste management  cost
  methodology.
SOURCE:,  SWEC
                          FIGURE 5.3-9  LINER COSTS
                                     319

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                               5,000                  10,000

                       VOLUME OF DRAIN  MATERIAL, yd3
  Examples 1 & 2  require only  drain  material due  to the  valley  shape;
  leachate containment is performed by the contaminated runoff catchment pond
  of which the leachate is a negligible component.

  Example 3 includes cost  of toe  ditch for collection due  to  broad  valley  at
  waste pile toe;  containment is  also by  the  contaminated runoff catchment
  pond.

  Example 4 includes  toe ditch collection and separate  containment pond
  because,  in  this case,  contaminated runoff is contained in  evaporation
  ponds on the waste pile surface.

  Example 5 includes only the drain material cost of Examples 3 & 4.

  Example 2 is  specific to  the TOSCO II  case studies,  except  the  Colony
  proposal  includes a  layer of drain material only  at the toe of the fill
  slope.

  The costs indicated are cumulative for the project life.

  See  Section 6.2.3 for details  on  the  solid waste management  cost
  methodology.
SOURCE:  SWEC
                  FIGURE 5.3-10  LEACHATE COLLECTION COSTS

                                     320

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      Groundwater collection systems typically consist of blankets or zones of
 pervious sand  and  gravel  drained beyond the perimeter of the landfill.  This
 may be  augmented with  embedded perforated pipe to increase capacity and with
 collector ditches.   The sand or gravel layer would be lined as necessary with
 filter fabric or surrounded by properly graded sand filters to prevent infil-
 tration of  smaller particles  from adjacent materials.  The  system  must also
. be designed to maintain its continuity despite possible subsidence or settle-
 ment of the landfill.
                                                                 !

      The costs of two groundwater collection systems were estimated and these
 are plotted  in Figure 5.3-11.   Both  systems used gravel  blankets  under the
 pile to  collect the groundwater seepage.   In Example 2  the gravel  blankets
 were used only  above the  seeps and springs,  while  in Example I an extensive
 network of  the  blankets  was  considered,  resulting  in  a higher cost.   The
 cost of the collection  system should be proportional  to  the quantity of the
 drainage material  used.

 5.3.4  Surface Stabilization Technologies

      The activities  and  technologies  in the  area  of surface  stabilization
 involve  the  treatment  of  the  disturbed  land  surface  and  the  problems
 associated  with  the disposal   and  reclamation of the waste  material.   These
 technologies  are  outlined  in  Figure 5.3-12 and  their  key  features  are
 presented in Table  5.3-5.

      Dust Control—

      The purpose  of dust suppression  is  to  limit  pollution from  airborne
 dust,  particularly during  the placement of  the  waste material  in a  fill.
 Oust suppression  can  be  accomplished by  spraying  the haul  roads and  fill
 surface with  water or  a  combination  of water  and a chemical binder.   Haul
 roads  could, alternatively, be paved.

      Use of water alone  for dust  suppression  would  necessitate  repeated
 applications,  often more  than one  per day,  to  be effective.  Water with  a
 chemical  binder should  necessitate only a few applications to a given  surface
 to  stabilize,  it   for  a  year or  more  unless  it receives  heavy  traffic.
 Finally,  vegetation would provide perhaps  the most permanent means of  dust
 control,  but this  would not be practical except on surfaces  which  would not
 be disturbed for a  number  of years.

     The dust suppression technology  assumed  in developing the cost data for
 two examples consisted of  routine  spraying  of the processed  shale  pile  with
 water  and additives to .minimize the dust generated due  to the wind and the
 waste  hauling  and  placement  activities.   Depending  on  the  processed  shale
 characteristics,  this operation  could either be  continuous  or intermittent.
 The cost curve in   Figure  5.3-13  is based  on the assumption  that both  the
 manpower and equipment  operation  requirements  are continuous.  Theoretically,
 these  requirements  could differ depending on the rate  of waste production and
 the surface  area of the particular waste pile; however, both cases  estimated
 were assumed to be  equivalent  in  this  respect.
                                     321

-------
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                    0.1    0.2   0.3   0.4    0.5    0.6    0.?   0.8

                          VOLUME OF DRAIN MATERIAL,  I06 yd3
0.9
  Examples 1 & 2  consist of  gravel  blankets for  collection of groundwater
  from springs  and seeps; extent  of blankets dictated  by the existence and
  extent of such conditions.

  Example 2 is  specific to the  TOSCO II case studies,  except the drainage
  layer  is  placed  only above  seeps and  springs  according to  the  Colony
  proposal.

  The costs indicated are cumulative for the project life.

  See  Section 6.2.3  for details  on  the  solid waste  management  cost
  methodology.
SOURCE:  SWEC
                 FIGURE 5.3-11  GROUNDWATER COLLECTION COSTS
                                      322

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                            DUST
                           CONTROL
   WATER AND
   BINDERS
   PAVE HAUL
  ' ROADS

L— REVEGETATION
ounrMw:
STABILIZATION
CONTROL
TECHNOLOGIES




EROSION
CONTROL



                                                 MULCH
                                              L— REVEGETATION
                         STABLE SLOPE
                            DESIGN
SOURCE'  SWEC
      FlGURE 5.3-12  SURFACE STABILIZATION TECHNOLOGIES

                             323

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     Erosion Control—                                           ,

     The purpose of erosion control is to keep the waste material in place so
that the surface drains remain free flowing, the slopes remain stable, eroded
material does  not pollute surface streams,  and  reclamation and revegetation
efforts are  not hampered.   Some means of limiting erosion  include contouring
the  surface with  short  and  gentle  slopes, providing  for drainage  of the
slopes  at  frequent  intervals,  using  mulch or  filter fabric to  dampen the
impact  of  water  flow,  and  revegetating  the  completed  faces.   Of  these
measures,  grading  and drainage  are  essential,  take effect immediately, and
last as  long as they are maintained.  Mulch or  filter fabric also provide a
quick control,  but they  are of a  temporary nature.   Revegetation provides a
permanent control, but it is generally slower to take effect.

     A  major  consideration  in  planning  erosion  control  measures   is  the
severity of  rainfall  in  the  area.  A  large proportion of the, water from a
high-intensity  rainfall   would  run  off  the  surface,  thus  increasing  the
erosion.

     Reclamation and ,revegetation consist  of placing a  subsoil and topsoil
strata  of  sufficient thickness  to support  vegetation, and then seeding the
disposal area with native or introduced species.   The greatest contributor to
the  magnitude  of  cost  for  this  control  technology  is the thickness of the
soil strata  and the costs associated with the delivered soil material, i.e.,
the  source  development,  processing  and  hauling  costs.   Soil  and  subsoil
stripped from  the  disposal  site may not be  available in sufficient quantity
to  meet the reclamation  needs.   The cost  curves  presented in  Figure 5.3-14
illustrate  five  examples.    Examples I  and 5  included   2 feet of  subsoil
(sand-gravel material) and  30 inches  of topsoil, both of  which  were brought
in  from off-site  sources  and thus had additional costs involved.  Examples 2
and 3 also  used the  same thicknesses, but  the  soils were available on the
site.   Example 4  used  no  subsoil  and only 6  inches  of  topsoil which  was
available  on  the  site;  therefore,  additional  material  costs  were  not
involved.   All  examples  included  the  cost  of  revegetation.  It  is  evident
from the  figure  that the  cost  of  erosion  control can  vary  significantly
depending on the  factors  considered;  however, in any category,  the costs are
proportional to the area reclaimed and revegetated.

     Stable Slope Design—

     The  purpose  of  designing  the  slopes  to  be  stable  under  prevailing
conditions  is   to  minimize  the maintenance of the landfill  and to  avoid
hampering  of the  reclamation and revegetation efforts.   The techniques  used
in  designing stable slopes  are  a well developed part of  soils  engineering.
To  arrive  at the  most advantageous slope design, other factors  besides basic
stability,  such as  erosion,  ease  of placement, reclamation and  revegetation,
must  be considered.   However,  the physical  characteristics  of the  waste
material will   dictate  a limiting  slope  angle.   The  costs of achieving  a
stable slope design are  incidental  to the  placement and  revegetation of the
fill material;  hence,  additional costs are not involved.
                                     326

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   60


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 5,3.5-  Hazardous  Waste Control  Technologies

      The control  of hazardous  waste  involves  its permanent impoundment  in  a
 permitted disposal  facility.   This facility may be  built on the project site
 or the  wastes  may be  sent to an existent,  off-site permitted facility.   These
 options are  outlined  in Figure  5.3-15 and  their key  features are presented in
 Table 5.3-6.

      On-site Disposal—

      Hazardous  waste  lagoons  are a  well  developed  and accepted approach  to
 solid waste  management.  They  are actually an  integration of  several control
 technologies  discussed in  Sections  5.3.2, 5.3.3 and  5.3.4.    Some  of  the
 included technologies  would be  an embankment surrounding  the  lagoon, a  runon
 diversion system, one  or two bottom  liners, a  surface  cover,  reclamation  and
 revegetation,  and monitoring.

      There_ are certain advantages to  building  a hazardous waste facility  on
 site.   This  option  automatically assumes  segregation of  the hazardous  and
 nonhazardous  wastes  and,  hence, their  separate  disposal.   An  advantage  of
 this  approach  is  that  much  of  the material necessary for  the  lagoon would  be
 available on  site  or  it already would have   been  brought in  for the non-
 hazardous waste  landfill.   Furthermore,  transport of  the wastes beyond  the
 property boundaries  will  not be required.  A  significant  advantage  may be
 that  the producer of the  hazardous wastes (the  oil shale developer) will have
 complete control  over  the disposal of  the wastes.

      There  are   also   certain   disadvantages   to  on-site   disposal  of  the
 hazardous  wastes.  To  be  efficient   in  evaporating  the liquids  and consoli-
 dating  the sludge,  the lagoon  should  be located preferably on a level site,
which may not  be readily available.   Rugged,  uneven  terrain would increase
 the cost  of site  preparation, runon control and reclamation.  There is also a
possibility  that  the  lagoon may  interfere  with other  ongoing activities and
the resource recovery.

     Off-site Disposal —

     Off-site existent  faci1ity.  This would be an already existing facility
where the wastes  can be disposed of  on  an "as needed"  basis.   A payment is
required  for every  shipment, but the cost may be  lower than that of building
and  maintaining  a  new  facility.   Also,  a significant  amount   of  time and
effort  involved in  the licensing, design, and construction of a new facility
can be  saved.   The  capacity and  distance of the existent facility must also
be'considered in selecting the disposal approach.
                                     328

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     HAZARDOUS
     WASTE
     CONTROL
     TECHNOLOGIES
                             ON-SITE
                             DISPOSAL
                             OFF-SITE
                             DISPOSAL
 SOURCE:  SWEC
FIGURE  5.3-15  HAZARDOUS WASTE CONTROL TECHNOLOGIES

                        329

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                                   SECTIONS

                            POLLUTION CONTROL COSTS


      This section provides  an  analysis of estimated pollution  control  costs
 for the TOSCO II case  studies  analyzed in this manual  (see  Sections 2 and 3
 for descriptions of these  case studies).   Section 6.1  presents  fixed capital
 and direct annual  operating costs for each control and  explains  how they were
 developed.   These  costs are referred to as the "engineering costs."

      Section 6.2 explains the  cost  analysis methodology used to  develop the
 total  annual  and per-barrel  pollution control costs.   These  costs  combine
 capital  and annual  operating costs,  allow for taxes,  and incorporate a return
 on investment.   This  is an  approach  similar to that which a private developer
 might use to determine  costs or assess the economic feasibility  of a project.
 Section  6.2 also details the economic assumptions that are incorporated into
 the calculation  of total  annual control costs.

      Section 6.3 presents estimated  total  annual  control costs and per-barrel
 costs for each  control  using  a set of standard economic assumptions.   These
 costs are  assembled  into total  per-barrel costs  for  air, water,  and  solid
 waste pollution  control  for the  case studies examined  in  this  manual.   This
.section  also examines  the sensitivity of the per-barrel control  costs  to a
 series of changes  in  the engineering costs and economic assumptions.

      Section 6.4 provides more detailed  information supporting  Sections.6.1,
 6.2  and 6.3.  .Section 6.4.1   provides  the  algorithms that  were  used  to
 determine  total  annual  control  costs  and  per-barrel  control  costs,  and
 Sections 6.4,2   and  6.4.3  provide  examples,  respectively, of  fixed  charge
 rate calculations  and cost  levelizing calculations.

      Section 6  uses a  large number of cost and economic terms.   The  inter-
 relationships  among  the more  important  of these  terms  is  illustrated  in
 Figure 6.0-1.   Each term is explained when it is  first used  in  the text, but
 the reader  may  find  it  helpful  to  use  this figure to provide  an  overview
 while reading  the various  sections.   In  addition,  Table 6.2-4,  presented
 later in  this   section,  indicates  the estimated  relative  magnitude of  the
 components  of per-barrel control  cost for a typical  major pollution control.

 6.1  ENGINEERING COST DATA

 6.1.1 Bases of  Engineering Cost  Data

      Throughout  this  manual a  distinction is made between capital  costs  and
 annual operating costs.  There are  two types of  capital  cost,  fixed capital

                                      331

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and  working capital,  and  two  types  of annual  operating cost,  direct and
indirect.

     Fixed  capital   is  investment  in  construction  and  equipment,  whereas
working  capital  is  money  that  is  required to operate  the plant,  e.g., that
which is tied up in inventories.

     Direct  annual  operating costs include  maintenance,  operating supplies,
operating  labor  and  utilities  costs.   Indirect  annual  operating  costs
comprise  additional   annual  costs,  i.e.,  property  tax  and  insurance,  an
allowance for extra  start-up costs,  a credit  for  severance tax not paid and
by-product credits.

     Section  6.1  only  considers  fixed  capital   costs   and   direct  annual
operating  costs.   Working  capital  and  indirect  annual operating  costs are
considered in Section 6.2.

     Assumptions Used to Develop Costs—

     A.11 • costs  are  expressed  in mid-1980  constant dollars.   The following
data apply  to air and water pollution control costs.  Solid waste management
costs were  developed  on  the basis that  these  activities  are contracted out,
since they are all  construction-type activities (see discussion later in this
subsection).

     Fixed capital  costs.   Fixed  capital  costs  are  of  the  "preliminary
estimate"  category.    Physical  plant  costs  for air emission  controls were
developed by Stone and Webster  Engineering Corporation (SWEC)  and for water
pollution  controls  by  Water Purification  Associates  (WPA).   Actual  vendor
quotes were used for major items of equipment; costs for other equipment were
obtained  from data  files  maintained  by SWEC and WPA.  Total  physical  plant
costs were  developed  from  the  equipment costs by  adding  appropriate allow-
ances for the following:

     »    Site preparation, excavation and foundations
     •    Concrete  and rebar
     •    Support structures
     •    Piping, ductwork, joints,  valves, dampers, etc.

     •    Duct and  pipe insulation
     *   . Pumps  and  blowers

     *    Electrical
     •    Instrumentation and controls

     •    Monitoring equipment
     •    Erection  and commissioning

     •    Painting

     •    Buildings,


                                    333

-------
     To  arrive at  the  total fixed  capital  cost,  the following factors were
added to the physical plant  cost:

     Engineering and
     construction overhead:        25% of physical  plant  cost.  '.

     Contractor's fee:             3% of bare module  cost (physical  plant
                                   cost plus engineering  and  construction
                                   overhead).

     Contingency:                  20% of bare module cost.


     For  an explanation  of  this  method  of developing  estimates  of fixed
capital  costs, see  Uhl  (June  1979).   A  20%  contingency  factor  was chosen
because there  are  only  pilot plant  data  for the TOSCO II  retorting process.

     It  is  considered  that  the accuracy  of these cost  estimates  is within
±30 percent.   Although  the   accuracy  of  a preliminary  fixed capital  cost
estimate  is normally  regarded  as  ±20 percent,  uncertainties about stream
magnitudes  and  composition   decrease  the  accuracy  of  these estimates  to
±30 percent.               '          .

     Direct annual operating costs.  There  are  two components which make up
the  total  annual  operating  cost.    The direct  annual operating  cost can be
regarded  as the  basic  (or  engineering)  cost,  while   calculation  of  the
indirect  annual  operating  cost makes  some adjustments  to  this,  cost.   E5y-
product credits are  included in the indirect annual operating cost.  Data on
the bases of direct annual operating costs  are  given below, while  the bases
of indirect annual operating costs are outlined  in  Sect.ion  6.2.

     Direct annual  operating costs are made up  of the  following components:

     •    Mai ntenance
     «    Operating supplies
     *    Operating labor

     •    Utilities
          --Cooling water

          —Steam

          —Electricity

          —Fuel  oil and gases.                                  ;

     Maintenance  costs   include maintenance  labor  and  replacement  parts,
consumables  used for maintenance, etc.

     Operating  supplies are  consumable  items (such as chemicals)  used in the
regular operation of the control (as opposed to use for maintenance).
                                     334

-------
      Operating  (and  maintenance)  labor  is  costed at  $30/hr.   This  is  a
 "loaded"  rate,  meaning  that  it  incorporates  some  overhead-type  costs  to  avoid
 developing  them separately.   The  rate  is  made  up  as  follows:

       A.   Wages  for  direct  labor                    $11.00/hr

       B.   Fringe benefits (45% of  A)                   4.95

       C.   Field  supervision (15% of A +  B)             2.40     ;

       D.   Overhead (50%  of  A> B + C)                 9.20

       E.   General &  administrative charge
            (9%  of A + B + C> D)                        2.45

                Total                                  $30.00/hr

      In  mid-1980, examination  of union  agreements  showed that oil  refinery
 direct  operating labor  was   receiving  approximately  $10/hr   in  Colorado.
 Hov/ever,  it is  anticipated  that  when  oil shale development occurs, this will
 bid  up  local labor rates, so $ll/hr,  which  was used for  the oil shale PCTMs,
 is  a  reasonable   value.   The  multiplier   factors,  used to  arrive  at the
 "loaded"  labor  rate  of  $30/hr,  were suggested  by  SWEC based  on  project
 experience  in the western U.S.A.

      Cooling water is  costed at  11.3 cents per  10s gal  circulated  (3
-------
of a  construction  nature,  subject to uncertainties similar to those inherent
in fixed capital costs.

6.1.,2  Details of Engineering Costs

     Tables  6.1-1  through  6.1-4  present details  of the fixed  capital  and
direct annual  operating costs for each air and water pollution control.  The
operating costs  relate to  a year of normal operation, i.e. , full production.
For the  start-up period,  direct annual  operating  costs  are  modified to an
appropriate level by the cost analysis methodology.

     Table 6.1-5 details the solid waste management  costs on  a year-by-year
basis.  These costs are allocated to fixed capital or direct annual operating
categories in Section 6.2 (Table 6.2-3).

6.2  COST ANALYSIS METHODOLOGY

     In the  cost analysis,  engineering cost  data  are  transformed  into  two
primary measures—the  total  annual  pollution  control  cost and.' the control
cost  per  barrel  of  shale  oil.   These  costs  incorporate both  capital  and
annual operating costs and consider project timing, taxes, and the necessary
return on investment.

6.2,. 1  Overview of Cost Analysis Methodology

     In private  industry,  one of the most widely accepted methods of evalu-
ating the economics  of a project is the discounted cash flow (DCF) approach.
Using  this  approach,  a project must  be able  to  demonstrate  that  it  can
produce some  established minimum  rate  of return on investment—known as  a
"hurdle" rate—to be acceptable.    .                       .      :
                                                                 i        ^
     One method for applying the DCF approach to  a complete oil shale project
is to determine the selling price which would provide the  revenue required to
produce a minimum  acceptable rate of return  (DCF ROR).   With  this method, a
selling price for oil can be established by distributing the required revenue
uniformly over every barrel of oil produced.

     The  same  technique can  be utilized to  determine  the  total  annual  and
per-barrel costs of pollution control.  In practice, pollution control is not
a  separable  aspect  of  an  joil  shale  project.  Consequently,  a  private
developer will, require  the  same  DCF ROR on  pollution  controls as  for  the
entire project.

     If  the  revenue  necessary to  provide  the  required DCF ROR  for  each
control (expressed  in  constant  dollars)  is  distributed uniformly  over each
barrel of shale oil produced, then this also implies a constant total revenue
requirement  in  each  year  of  normal  (full) production.   However,  in  the
start-up years, less oil is produced, with the result that the annual revenue
requirement  is  prorated.   Additional costs  incurred in the start-up period
were  spread  over  all  production  in order to produce  a  uniform per-barrel
control cost.
                                     336

-------


























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     The  total  annual  required  revenue  is  utilized to  satisfy  two major
components:  the  total  annual  operating cost, and  a component that provides
the necessary return  on investment, called the  total  annual  capital  charge.
Note  that  with  the  DCF  approach,  profit  is  based  solely  on  investment;
operating  costs are passed  straight through  as one  component  of the total
revenue requirement, without addition of any profit element.  This is normal
practice for industrial.project assessments.

     To relate  an annual  capital charge to  the corresponding investment, a
"capital charge rate"  was used.   In practice, there are two types of  capital
investment:  fixed  capital  (i.e.,  physical   equipment)  and working   capital
(which  is  nondepreciable  investment).   The "fixed charge rate" is defined as
the proportion  of investment  in  fixed capital  that  must  be  recovered in a
year  of normal  production  in  order to provide the  required  DCF ROR.   The
"working capital  charge  rate"  performs a  similar  function for  the working
capital.  The total  annual capital  charge for a pollution control is  the sum
of  the  annual   fixed capital charge  and  the annual  working capital  charge.

     Fixed  charge rates have several economic assumptions  embedded in them.
Some  of these   assumptions  are common  to  all pollution  controls,  i.e.,  the
project life  and  operating  (stream) factors, the  income tax  rate,  and the
required DCF ROR.

     Other  assumptions  vary according  to  the pollution  control  or group of
controls.    These  are:   the  timing  of  the  investment in  fixed capital,  the
depreciation period,  and  the  investment  tax  credit details.   Consequently,
different  fixed  charge  rates are  used for  different  groups of  pollution
controls.*   (These  rates,  as  well  as   the underlying  standard  economic
assumptions, are  listed later in Table 6.2-2.)                             .

     The working  capital   charge  rate depends only  on the  project life and
operating  factors,  the timing of the investment in working capital  and the
required DCF ROR.   Since none of these assumptions varies among controls, the
same working capital charge rate is used for each control.

     As already indicated,  the total annual cost for a control is the sum of
the total  annual  capital  charge  and the  total  annual  operating cost.   The
total   annual  operating  cost comprises two  components.   The  "direct  annual
operating cost" consists  of maintenance,  operating supplies, operating labor
and utilities.    The  "indirect annual  operating cost"  comprises  an  annual
allowance  for  property taxes  and insurance,  any annual  by-product credits,
and an  allowance  for  extra start-up costs, i.e., those that are in excess of
the direct  annual  operating cost  prorated in accordance with production.   It
also includes a credit reflecting a reduction in the  Colorado severance tax
* The  use  of  several  different  fixed  charge  rates  in  the same  oil  shale
  PCTM  may  appear  complex.   However,  since  the  manuals  examine  several
  alternatives  for  pollution  control,  an  accurate  evaluation of  capital
  charges  is  needed.   A  less  accurate  approach,  such as assuming a single
  capital  expenditure  profile  for  all  controls,  could conceivably  affect
  the per-barrel cost ranking of pollution control alternatives.

                                     342

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that  must be  paid,  because the  cost of  each  pollution control reduces  the
severance  tax  liability.*  Extra start-up costs and the  severance tax  credit
are  "levelized"  to  distribute  them uniformly  over  each  barrel  of shale  oil
produced  since they  do  not vary  in proportion to  production.   (Levelizing
takes  a cost  that  does  not  vary in proportion  to production  and  finds an
economically  equivalent  cost  that  has  the  same  time-profile  as, production
[see Sections  6.2.3  and 6.4.3].)  To summarize:

     Total Annual Control Cost = Annual  Fixed Capital Charge + Annual
     Working Capital Charge + Direct Annual Operating Cost + Indirect
     Annual Operating Cost.                                      :   .

     For  air and water pollution controls, direct annual operating costs  are
specified  for  a  normal  year of production and  are implicitly prorated  during
the start-up years.   In practice, operating costs during the start-up  period
will  be  higher, but this  is  allowed  for via  the  extra  start-up  costs
discussed  in  Section 6.2.2.   The solid  waste management  costs are developed
in  the form  of  a  year-by-year  cash flow  (see  Table 6.1-5) which  must be
converted  into equivalent fixed capital  and direct annual operating costs  for
a full production year (see Section  6.2.3 and Table 6,2-3).

     The  per-barrel  control  cost  is obtained  by  dividing the  total   annual
control cost  by the  production  in  a  normal (full  production)  year.   (Per-
barrel  operating costs  and capital  charges can  be  calculated in the same
way.)   The detailed  algorithms  for  these  calculations  and  for determining
fixed and working capital charge factors are given in Section 6.4.1.

6.2.2  Economic Assumptions Used in Total Cost Calculations

     To transform engineering  cost  data provided in Section 6.1.2 into total
annual  capital  charges,   total annual  operating costs,  and total annual  or
per-barrel control costs,  a  number of economic assumptions were made.   Most
of these  assumptions are  listed  in Table 6.2-1,  and  Table 6.2-2 summarizes
those  assumptions  that vary  from control to  control.   The  values given in
these  two  tables are  the standard  values,  known  as  the "standard  economic
assumptions," which have been used for the cost analyses presented in  the oil
shale PCTMs.   Some of these  are varied  in the sensitivity analyses which are
used to  show  how control costs  change  in response to alternative  economic
assumptions and to changes in the engineering costs.
* The distinction  between the  two  components of operating cost  is  made for
  convenience  in  performing  the  calculations and  is not  fundamental.   The
  direct annual operating  cost  is comprised of basic  cost  elements, whereas
  the indirect annual  operating cost comprises a series  of adjustments that
  are influenced  by other  factors, .such as  tax  assumptions.   Direct annual
  operating costs  for each control  are given in Tables  6.1-1  through 6.1-4
  and 6.2-3.   Indirect annual  operating costs for all controls are calculated
  using a standard  algorithm  (see Section 6.2.2), except for any by-product
  credits which are given in Tables 6.3-4 and 6.3-5.

                                     343

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                       TABU 6.2-1,  SUMMARY OF STANDARD COST AND ECONOMIC ASSUMPTIONS
                                                 Assumptions
COST ASSUMPTIONS
«    Base Year:  Mid-1980 dollars
«    Basic Labor Rate:  $11.00/hr*
•    "Loaded" Labor Rate*:  $30.00/hr
«    Fixed Capital Costs:  25% engineering and construction overhead and 3% contractor's fee. included*
«    Contingency Allowances:  20%, all fixed capital costs*
                               0%, most operating costs*
                              20%, solid waste direct operating costs
ECONOMIC ASSUMPTIONS
•.    Project Life:  20 years*
«    Normal Output:  47,000 Barrels per Stream Day (BPSD)
•    Operating Factors:  Year 1      -  50%                                          •
                         Year 2      -  75%    .
                         Years 3-20  -  90%*                       '                         ;
•    Approach:  Discounted Cash Flow Evaluation (DCF)*
•    Discount Factors:  Discrete,* year-end basis
•    Method:  Determination of Revenue Requirement to provide specified DCF ROR*
•    Technique:  Annual Capital Charge plus Annual Operating Cost
•    Required DCF ROR:  12% (100% Equity Basis)*
•    Cost Escalation:  None (constant dollar evaluation)*
•    Combined State and Federal Income Tax Rate:  48%*                        '            '
«    Depreciation:  Method  -  Sum-of-Year's Digits*
                    Period  -  16 years, most items*
                               10 years, solid waste area
                                5 years, mobile equipment
»    Investment Tax Credit:   20%, most items*
                             •13 1/3%S mobile equipment
•    Additional Start-up Costs (in Year 1):  3%.of fixed capital, plus 20% of a normal year's direct
     operating cost                                                                                         •
«    Working Capital:  30 days' total operating cost (excluding by-product credit), plus 60 days' by-product
     credit                          .    '   .
•    Annual Allowance for Property Taxes and Insurance:   3% of fixed capital
•    Colorado Severance Tax:  Credit allowed
•    Timing of Investment:  Initial fixed capital expenditures can occur in Years -3 through +3;
     expenditures and tax considerations for each control are phased in accordance with the construction
     and initial operation of each control (see Table 6.2-2 for schedules),                 :   .     .
«    Corporate Financing:  Tax credits and allowances can be passed through to a parent company that can
     benefit from them immediately, without waiting for the project to become profitable*
«    Federal Depletion Allowance:  Does not affect pollution control costs
* These methods and factors are in accordance with the recommendations, dated April 22, 1980, of EPA's
  ad hoc synfuels cost committee.
Source:  DRI.

                                                    344

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      Where  appropriate,   the  standard  economic  assumptions  are  discussed
 below.   Others are discussed  in  connection with the sensitivity  analyses  in
 Section 6.3.2.                                                   ;

      Timing of Control  Capital  Expenditures—•

      Table 6.2-2  includes  the fixed  capital  expenditure  profiles for  each
 category  of  control.   The  construction  schedule  is based  on Colony's  PSD
 permit  (Colony ,Development  Operation,  1977).   Engineering judgment was  then
 used  to  determine  when   the  pollution   controls   would   be   procured   and
 installed, incorporating the impact  of payments  made  during off-site  fabrica-
 tion.   In  general,  expenditures  on controls  tend  to be incurred  later  than
 those for most  retort construction activities, since  the  controls  are  usually
 among the last  items to be  installed.

      Part of the  water pollution control  system constitutes an exception  to
 the  above  discussion.   Basic site  water  management facilities must  be  in-
 stalled and operational before most other activities  can commence.  Conse-
 quently,  these  items  were assumed to be installed  in Year -3  (i'.e. ,  4 years
 before  production commences)  and placed  into service  in Year  -2  for deprecia-
 tion  purposes.

      Assumptions for Taxation*—

      Depreciation.   All  oil  shale  PCTMs  used a 16-year depreciation period
 for  most  assets.    This  corresponds  to  the  mid-point of  the  IRS'  Asset
 Depreciation  Range  (ADR)  guidelines for  oil  refineries.   In practice,  many
 companies  would use  the   lower end  of  the  ADR range,  which  is 13 years;
 however,  it has been found that this would make very  little difference in the
 results of the analysis.                                         .

      Some  equipment  clearly qualifies   for a  shorter  life.   Capital items
 associated  with processed shale disposal,  i.e., embankments, runon  diversion,
 and  water  impoundments,  were  regarded  as mining  equipment,  for which  a
 10-year  depreciation period  was used.   A 5-year depreciation period was used
 for the  mobile  diesel  equipment,  and it was assumed  that this equipment was
 replaced three times during the project life.

     The  depreciation   method  used  for all  taxation  calculations was  the
Sum-of-the-Year's  Digits method.
* All analyses were conducted prior to enactment of the Economic Recovery Tax
  Act of 1981  (PL  97-34).   As far as an  oil  shale project is concerned, the
  main  impact  of  this  act is  to  permit very  rapid depreciation  under the
  Accelerated Cost Recovery System (ACRS).   Using ACRS, most  property would
  be depreciated over  5 years and  mobile equipment would be depreciated over
  3 years.   A rough estimate  of the effect of the provisions.of the Economic
  Recovery  Tax   Act  of  1981  on the  pollution  control  costs  is  given  in
  Section 6.3.1.


                                  .346                          •

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      Investment  Tax Credit (ITC).   A basic 20% ITC was  used for all  items  in
 accordance  with  the Energy Tax  Act  of  1978 (PL  95-618).   The mobile equipment
 has  a  depreciation period  of  only 5 years,  so the  credit  is  reduced  by
 one-third,  to  13 1/3 percent.                        -            ;

      Where  payments for  a control   extend over  more  than one year, the tax
 credit  can  be taken as the  capital is expended, in accordance with  the  IRS1
 progress payments  rule.   Otherwise, it  is  taken when the  asset is placed  into
 service.                                                         :

      Under  present  tax law,  equipment associated with hydrotreatment  (i.e.,
 the  ammonia recovery unit) would not  qualify for the 20%  ITC and would  only
 receive 10% ITC.   This restriction  was  not taken  into account in the  calcula-
 tions;  however,   had it  been  incorporated,  the air pollution control  cost
 would only  be increased by about one cent per barrel under standard  economic
 assumptions.

      Income tax  rate.  A  combined State and Federal tax rate  of 48% was used.
 In  practice, Colorado has a 5%  tax rate, so  the  effective  percentage  rate
 should be:   5 +  ([1 - 0.05] x 46) = 48.7%.  The error introduced by using 48%
 is negligible.

     Depletion allowance.   The  Federal  depletion  allowance  has  not  been
 incorporated into  the calculation of taxes.  The  justification for this is  as
 follows.  The  percentage  depletion allowance is 15%  on  the "gross income"
 from  an oil shale property.  In this case, since the sales or transfer price
 of shale  oil (and, hence, gross income)  is independent of pollution control
 costs, the  depletion allowance  will not affect  those  costs.   However,  there
 is a  limitation  that the  percentage depletion allowance cannot  exceed 50%  of
 the  taxpayer's  taxable  income from the property,  computed without allowance
 for depletion.  Since pollution control costs reduce the taxable  income, they
 could affect the depletion allowance if it was limited under  the  above rule,
 and this would  then be  a  cost attributable to pollution control.   While this
 might well  be the case  in a start-up year,  it appears  that this limit  is
 unlikely  to apply during a  normal year's operation.   This  is  because  the
 complete  project's  total  annual   operating  costs  are  a  comparatively  low
proportion of its  total  annual control  costs,  including capital-related costs
 (Nutter and Waitman, 1978).

     Hence,   the   impact   of  the  Federal   percentage  depletion  allowance  on
 pollution  control  costs   has  been  disregarded.   This  may  introduce  minor
 errors during start-up years, but complete project cost data are .not publicly
 available to permit the  effect to be calculated.   Cost depletion, which might
 at times be taken instead of percentage depletion,  is  clearly irrelevant to
pollution control costs.

     Other Assumptions—

     DCF ROR.  Twelve percent (per year)  was used as  a  standard assumption
(see Section 6.3.2).
                                     347

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     Project life.  The expected project  life (measured  from the commencement
of  production)  will  be determined by exhaustion of the  oil shale  reserves  or
by  technological obsolescence.  Planned project lives used for evaluations  of
oil  shale  developments range from 18 to  30 years.  Twenty years  is a common
period  to  use  for   economic  evaluations  and  was  used  in  this  manual.
Increasing the  life has a very small effect on the results at normal DCF RORs
(i.e., 12% or more).

     Start-up profile.  The start-up profile and normal  year operating factor
are  based  on projections  for a TOSCO  II plant  (Nutter and Waitman, 1978).
The  operating  (stream)  factors  are as  follows:   Year 1 - 50%,  Year 2 - 75%
and Years 3-20 - 90%.

     Components of Annual Indirect Operating Costs—

     The annual indirect operating cost is composed as follows:

          Annual property tax and insurance allowance
          + Extra start-up costs (levelized)

          - Severance  tax credit (levelized)
          - Annual by-product credit (if  any).

     Property tax and  insurance .allowance.   The  annual  indirect  operating
cost includes 3%  of the fixed capital  cost  as  an allowance for property tax
and insurance.  This value was selected by DRI after review of a wide variety
of sources..                                                      '

     Extra start-up cost.  The total extra start-up cost (which is treated  as
an operating cost, as  opposed to being capitalized) is derived from the fixed
capital and direct, annual  operating costs.  The capital-related component  is
3%  of the  fixed capital  cost as an allowance for "fix it" costs.   The opera-
ting cost-related component, which is 20% of a normal year's direct operating
cost, allows  for hiring  and  training  employees  before production commences
and  for  higher unit  costs  during the  start-up period.  This value  for the
extra  start-up  cost  for surface  retorting  plants  with  a  2-year  start-up
period was selected  by DRI  after  a  review  of several  sources, including
estimates for TOSCO II (Nutter and Waitman, 1978) and Paraho (Pforzheimer and
Kunchal,  March 24, 1977)  plants.   The  extra start-up cost was  assumed to be
incurred during  the first year of  production but is levelized to spread  it
uniformly over  every  barrel  of oil  produced (see  Sections 6.4.1  and  6.4.3).

     Severance tax credit.     Under   Colorado   HB 1076,   enacted   in   1977,
severance tax is  levied  on  the production of a commercial oil  shale facility
at the rate of  4% of  the "gross proceeds"  for surface retorted oil.   "Gross
proceeds" is defined  as  the value of the oil  shale at the point of severance
and is calculated by  subtracting  costs (e.g., retorting and mining) from the
gross sales income.   Since  pollution controls add to costs,  they reduce the
gross proceeds  by a  corresponding  amount.  Hence, a credit for severance tax
not paid should be deducted from the pollution control  costs.
                                     348

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      While   operattng  costs   are  cl.early  allowable  in   calculating  gross
 proceeds,  return  on  capital   does  not appear  to  be  (the  statute refers  to
 allowing  "...costs,   including   direct  and   indirect  expenditures   for:
 (a)  equipment  and machinery....").   Hence,  when  this credit  is  calculated,
 the  capital  charge must be replaced  by some form of amortization.   For this
 analysis,  the  severance tax  credit  calculations  are  based  on  direct  and
 indirect annual  operating costs,  plus  5%  of  the fixed capital  cost to provide
 capital  amortization  over the  20-year  project  life.              :

      In  applying this credit, allowance  was also  made for exemptions  to the
 tax  for the first 10,000  barrels per  day of  production and for  plants  that
 have not achieved 50% of their design capacity, together with  reduced rates
 of  tax  in the  early years.   The credit  is levelized in  order to achieve  a
 uniform  per-barrel cost.  The methodology utilized  (LFAC2 in  Section  6.4.1)
 is not precise,  but since the  severence tax  correction is typically less  than
 2%   of  the  total   annual  or  per-barrel   control  cost  (see  Section 6.2.4),
 further  refinement is not justified.*

      By-product  credits.  The  by-product  credit (if  any) for  each control  is
 shown in Tables 6.3-4  and 6.3-5.   (There  are no  salable  by-products  from
 solid waste management.)   By-product  values  of  $110 per ton  for  ammonia,
 $30  per  long ton for  sulfur, and  $32 per  barrel  for oils were  used.

      At  present,  there  is no significant  market  for sulfur  in the. Rocky
.Mountain  Region;  in  the past, shipping costs  to move recovered sulfur  to  a
 chemical complex could  have  been greater  than  its delivered value.   However,
 the  price of high quality sulfur has  gone up substantially in  recent  years,
 reaching values  as high as $129  per  long ton (U.S.  DOI, August 1981).   High
 demand  for  sulfur  is  projected   through  the year  2000 (Rangnow and  Fasullo,
 September 28, 1981).  Hence, a nominal  $30 per  long ton has been included for
 recovered  sulfur.    However,   if  in the   future  a  sulfuric  acid  plant  and
 fertilizer complex are developed  in the area, the values of by-product  sulfur
 and  ammonia would  be.raised.

      The by-product value  of  $32 per barrel for recovered  oil  is lower  than
 the  selling  price assumed for upgraded shale oil, which is  $36 per barrel.
 Most  of  the  by-product>  or recovered oil, is likely  to be recovered prior to
 upgrading, and  $32 per  barrel is  a  value  appropriate  for  light  shale  oils
 that  have not been upgraded.

     Working Capital—

     The  working   capital   associated   with  a  control  was  taken  as  one
 month's  total operating  cost  plus three months' by-product  credit.   This is
  Since this analysis was conducted, the Colorado Legislature has amended the
  severance tax  legislation pertaining  to  oil shale.  While  the  basic rate
  for aboveground  retorting is  unchanged,  the various  exemptions discussed
  above  are  reduced.   This  will  result  in  plants paying  slightly  more
  severance tax,  which marginally increases the severance tax credit, thereby
  mcirginally (much less than 1%) reducing the pollution control cost.

                                     349

-------
 equivalent to be one month's total  operating cost disregarding the by-product
 credit,  plus  two  months'  by-product  credit.   Two months'  by-product  credit
 represents one month's  inventory  and  one month's receivables.   These  values
 were  selected by DRI after review  of a variety of data sources.

      Working, capital is advanced  in accordance with  the direct annual  opera-
 ting  cost  plus the extra start-up  cost,  as  follows:

               Operating      Output as        Operating Cost        Working
              (On-Stream)     % of  Full       Relative to Full        Capital
                Factor        Production          Production      .   Increment

      Year  1      50%            56%               76%              76%

      Year-  2      75%            83%               83%

      Year  3      90%            100%              100%
      Seventy-six  percent is advanced in  Year  1 because  this  includes  the  20%
extra start-up  cost  (56%  +  20%  = 76%).   In  Year 2, the  operating cost
increases  from  76%  to  83% of  normal,   hence  7%  more working  capital   is
required.   A similar  argument  applies to Year 3,   leading  to a 17%  working
capital  increment.  All  working capital is recovered in  Year  20.

      The working  capital  charge rate  (RW)  is calculated  in a  similar way to a
fixed charge rate (see  Sections 6.4.1 and  6.4.2).  For 12% DCF  ROR and normal
project-timing assumptions,  RW - 20.83%.

6.2.3 Solid Waste Management Costs

      Throughout this manual  a distinction  is made between fixed capital costs
and annual operating costs.  The importance of this  distinction is related to
the treatment  for determining "income tax  liability.   Operating .costs can be
claimed as an expense in  the year in which they are  incurred, whereas  a fixed
capital  cost must  be  depreciated  over  the period for which the  asset is
expected to  be  used.   The effect of  classifying  a cost as an  operating cost
rather than  a  capital  cost  is to reduce the tax liability in any given year.

      For  air and  water  pollution  controls,  the distinction  between fixed
capital  and  annual  operating costs is  unequivocal.   For solid waste  manage-
ment  costs  which  are   developed  in  the  form of  year-by-year  cash flows
(Table 6.1^5),  the  distinction  is  less   clear.   Costs  that  occur  in only
Year  1 or  Years I,  2  and 3  were treated  as fixed capital costs, while those
that  continue for 15 or more years were considered as operating costs.  Costs
that  occur  at  the end of the project (e.g.,  regevetatipn)  were also  treated
as  operating  costs, since  there  is  no remaining project life  over  which to
depreciate them.  In  one case,  monitoring wells,.costs  occur in Years 0, 10
and 19.   Although  by  no means a  clear-cut decision,  this cost  stream  was
treated as an operating cost.

      Since the solid waste management operating costs are not proportional to
production, they  were  "levelized"  to transform them into  equivalent direct


                                     350

-------
annual  operating  costs that are proportional to production, so that they can
be  treated in  the  same way as other  direct  annual  operating costs.   Level-
izing involves  determining the annual  cost that is proportional to production
and which  has  the same present value  (for  a given OCF ROR) as the  irregular
operating  cost stream.   Further  explanation and an  example are provided in
Section 6.4.3.  Costs  designated as fixed capital were not levelized.

     Table 6.2-3  presents  the  solid waste management fixed capital costs and
direct  annual  operating  costs  (levelized  at  12% DCF ROR)  derived from
Table 6.1-5.

6.2^4  Control  Cost Example

     Table 6.2-4  provides  an  example of  the  composition  of  the various
elements of per-barrel control cost for a single major pollution control, the
diethanolamine  (DEA)  unit.,  Per-barrel costs follow identical proportions to
annual costs.

     It can  be seen  that the fixed  capital  charge amounts  to  39.3% of the
total  cost,  whereas  the  working capital  charge  is  only 1.1% of  the   total
cost.   It  is  interesting to note  that the  fixed  capital charge  is   almost
entirely return on equity, as the investment tax credit (20% of fixed capital
cost) almost offsets the income tax liability over the project life when both
are discounted  at 12%, which is the specified DCF ROR.   This, i llustrates the
effect  of  the  time-value  of money, as the tax credit is given before produc-
tion  commences,  whereas  the regular  tax  liability  is weighted  toward the
later years of  the project.                                           ,

   ,  For this particular control, the direct operating costs make up 51.9% of
the total  cost  and  are dominated by the  charge  for steam, although mainten-
ance is significant.   Several  other controls have very  large utility costs,
which points up the need for sensitivity analysis  (see  Section 6.3.2)   since
unit values  for utilities cannot be established with much certainty without
knowing more about the entire plant.

     The indirect operating  costs  amount to 7.7% of  the  total  cost for this
control, of which 7.3% results  from the cost of  property tax and insurance.
Extra start-up  costs  and the severance  tax credit  are each about  2%  of the
total.                     •   .

     Except  for the high cost of  steam,  these cost proportions  for the DEA
unit are typical of those for air and water pollution controls.   However, for
some controls,  the  indirect operating cost or  even  the  per-barrel  control
cost can  become  negative where  there is  a significant  by-product credit.

     Water  pollution  control   costs  tend  to  be   less  capital-intensive,
i.e., the  the  ratio of the  total  annual  capital  charge  to  the  total  annual
operating  cost  is lower.  This  is because  some  controls  have  high utility
costs.

     Solid waste  management  costs  are different in that  they  are basically
either a fixed  capital  cost  or a direct  annual  operating cost, but not both

                                     351

-------
        TABLE 6,2-3.  FIXED CAPITAL AND DIRECT ANNUAL OPERATING COSTS
                         FOR SpLID WASTE MANAGEMENT
Activity
   Fixed
Capital Cost
  ($000's)
 Direct Annual.
Operating Costc
  ($000's/yr)
SURFACE HYDROLOGY
   Runoff Collection
   Surface Cover
   Upper Embankment
   Lower Embankment
   Runon Diversion
   Stil1 ing Basins
   Water Impoundments
     209
     912C
     261fc
   4,015C
                              155
                              542
SUBSURFACE HYDROLOGY
Bottom Liner
Shale Underdrain
Monitoring Wells
Groundwater Collection
SURFACE STABILIZATION . .
Clear and Grub
Strip Topsoil
Dust Suppression
Reclamation and Revegetation

630
5
13
13

75
346
' 1,738
108

  The direct annual operating costs are 1 eve!ized with respect to production
  at 12% DCF ROR.
  Spent in first year of production, Year 1.
•c Spent uniformly in Years 1-3.
Source:  DRI.
                                     352

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Source:   DRI.
            TABLE 6.2-4.   PER-BARREL COST BREAKDOWN  FOR DEA UNIT!
                 (Standard  Economic Assumptions, Case Study A)
Cost Category                       Cents/Barrel         Percentage of Total
Fixed Capital Charge
     Equity Return (12% ROR)
     Income Taxes Paid
     Investment Tax Credit
                                     ~
                          :                 48.1                     39.3

Working Capital Charge                      1.3                      1.1

Direct Operating Costs
     Maintenance                     7.7                     6.3      '
     Operating Supplies              0.7                     0.6
     Operating Labor                 1.0                     0.8
     Cooling Water                  —                      —
Steam
Electricity

Indirect Operating Costs
Taxes and Insurance
Extra Start-up Costs
Severance Tax Credit
By-product Credit

TOTAL COST
50.7
3.4
63.5

8.9
2.8
(2.3)
--'
9.4
122.3
41.4.
2.8


7.3
2.3
(1.9)





51.9





7.7
100.0

                                     353

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 for  a  given  control.    This  reduces  working  capital  and  indirect  annual
 operating  costs,  respectively,  to  essentially  zero.

 6.3  COST  ANALYSIS  RESULTS                          ,                  ;

     The  methodology used  to develop the data  presented  in this section  is
 identical  to  a complete discounted  cash  flow  evaluation;  that is,  it  solves
 for  the per-barrel  revenue required to  provide  the  specified return  on the
 investment (DCF  ROR)  associated with a control.  This revenue  requirement  is
 known  as  the  total  annual  or  per-barrel  control  cost.   The cost methodology
 is   outlined  in  Section 6.2,   and  further   details   are   provided   in
 Section 6.4.1.                      .

     Two  control  items—proper  maintenance  of  valves  and  pumps  and the
 ammonia recovery  unit—have relatively large by-product credits which lead  to
 negative  total  annual  costs  (i.e.,  total  annual  cost  credits).   Although
 these  items might  consequently not be considered  pollution controls,  their
 costs  have been  included  in the  total  cost  of  pollution  control.   The net
 credits associated  with  these items are  a very small proportion of  the total
 control costs  (about 0.1% of the  total air pollution control cost for  proper
 maintenance of valves and  pumps,  and 4 to 10% of  the  total  water  pollution
 control cost for  the ammonia recovery unit).

 6.3.1  Results for Standard Economic Assumptions*

     The term  "standard  economic assumptions"  is used to describe the  normal
 economic assumptions  presented  in Tables 6.2-1 and  6.2-2.   The  majority  of
these  assumptions  are   in  reasonable  accord  with  normal  engineering and
 economic evaluation practices.  The most critical economic assumption is that
of 12% required DCF ROR.   This figure was adopted for the oil shale  PCTMs and
would  be  appropriate for  a mature  industry,  but  it  is  probably  low  for a
pioneer plant  at  this  time (see Sections 6.2.1 and 6.3.2 for a discussion  of
factors influencing the selection of a DCF ROR).
* As already mentioned, this analysis was developed prior to enactment of the
  Economic Recovery Tax Act of 1981.  The rapid depreciation (ACRS) permitted
  by  this  act  would  significantly reduce  the  values  of the  fixed charge
  factors,  especially for  normal  ("pass through")  financing as  opposed to
  stand-alone financing.

  For standard economic assumptions, very rough estimates of the decreases in
  total annual control costs are as follows:

          Air controls:       5% decrease on aggregate.
          Water controls:     10% decrease, on aggregate.
          Solid waste mgt.:   little change.              ,

  As an .alternative assumption,  if the energy portion (10%) of the investment
  tax credit were  allowed to  expire at the  end  of 1982, the combined effect
  of this  and ACRS would  be to  cause small  increases  in the  total annual
  control costs.


                                     354                   ,

-------
     Table 6.3-1  provides a  summary  of  pollution  control  costs  developed
using  the  standard  economic  assumptions  for  each  of  the  case  studies
considered in  this  manual.   Table 6.3-2 provides additional detail  based on
the control groupings listed in Table 6.3-3.

     Table 6.3-1  shows  that the  total  investment in  fixed capital  for  air
pollution  control  equipment   ranges  from  $91.8 million  (Case .Study C)  to
$106 4 million  (Case Studies A  and B),  while  the  total  air control  cost
ranges from $2.72 per barrel  to $3.35  per barrel,  respectively.-  Investment
in   fixed capital   for  water  pollution  control   equipment  ranges   from
$7.4 million  (Case   Study A)   to  $9.5  million  (Case  Study B).   The  water
pollution control cost  ranges  from 12  cents per  barrel (Case  Study C)  to 18
cents   per  barrel   (Case  Study  B).    Solid  waste   management  requires
$5.4 million in  fixed capital  and has  a control cost of 29 cents per barrel.

     Table 6.3-1  also  compares  the total  cost  of  pollution  control  to an
assumed  $36  per-barrel  value  for  upgraded shale  oil.*  For  air pollution
control,  the  proportion  ranges  from  7.6%  (Case  Study C)   to   9.3%  (Case
Studies A and  B).   For water pollution control, the range is from 0.3% (Case
Study C)  to 0.4% (Case Study A).   The  total  solid waste management cost for
all  case  studies is 0.8% of the  $36  per-barrel value  of upgraded shale oil.

     The  works-gate value of $36 per  barrel  (mid-1980 dollars) for TOSCO II
upgraded  syncrude was based on three sources:  a developer's estimate of $35
to  $40  per barrel  of upgraded syncrude,  a study for  the  U.S.  Department of
Energy by Lester W.   Scharmm (March  1980), and an MIT-Energy Laboratory report
(Weiss  Ball  and Barbara, June 1979).   Scharmm concluded that upgraded shale
oil  can bring  the  same  price  as the  best  light,  sweet, imported petroleum
crudes.   The  1980   price  of  such  a   petroleum  crude  was  about  $36.   The
MIT-Energy  Laboratory  report  suggests that  the cost  of  upgrading TOSCO II
shale oil would be   about $3.00 per barrel (in  1978  dollars) at a  12% rate of
return and that  the industry average cost would be about $4.00 per barrel (in
1978 dollars).   Since  the 1980  value of  surface  retorted  shale  oil  was
estimated to  be $30 per  barrel   (used  in  the  Lurgi-Open  Pit  PCTM),  the
MIT-Energy Laboratory data suggest that upgraded  syncrude  would have a  1980
value of  about $34 per barrel.   Considering  all  three data sources, a value
of  $36 per barrel was chosen for  the price of  upgraded shale oil.

      It  is generally anticipated that  the real price  of oil will  increase in
the future.   Hence, the  value  of $36  may be considered to be  a conservative
estimate  because it does not  include  any element of  escalation  relative to
the general  level  of prices.   For  example,  if oil prices were  to  escalate at
only'2% per annum  relative to general cost levels  (which  can  be  expected to
include pollution control costs),  the  real  value of upgraded  shale  oil would
reach $53 per barrel (in mid-1980 dollars) by  the year 2000, i.e., at the end
of  the  20-year project  life.
 * Other prices  for the value  of shale oil  are used in the other  oil  shale
   PCTMs, reflecting quality differences.
                                      355

-------














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                       TABLE 6.3-3.  CONTROL GROUPINGS
Group Designation
Specific Controls
Air Pollution Control

   Participate Control:



   Retort Gas Treatment:

   Miscellaneous Air:
Fabric filters, dust suppression, high
energy venturi scrubbers, venturi
scrubbers.

DEA, Claus, Wellman-Lord, Stretford.

Thermal oxidizers, low flare and
thermal oxidizer, oil storage tanks,
ammonia storage, proper maintenance of
valves and pumps, diesel emission
controls.                  :
Water Pol 1ution Control

   Condensate Treatment:
   Miscellaneous Water:
API oil/water separator, ammonia
recovery unit, foul water strippers,
bio-oxidation unit.

River water clarifier,* boiler feed-
water treatment,* cooling water treat-
ment,* equalization pond, runoff
oil/water separator.
Solid Waste Management
   Surface Hydrology:
   Subsurface Hydrology:
   Surface Stabilization:
Runoff collection, surface cover,
upper embankment, lower embankment,
runon diversion, stilling basins,
water impoundments.

Bottom liner, shale underdrain,
monitoring wells, groundwater
collection.

Clear and grub, strip topsoil,
dust suppression, reclamation and
revegetation.
* These technologies could be considered as part of the process rather than
  pollution control.                                           ,

Source:  DRI.                               •  .                  ...
                                     358

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      Cost Detai1s—

      Full  cost  details  for  each  control  (using  standard  economic  assumptions)
 are;  presented  in  Tables 6.3-4  through  6.3-6.   As  already  noted, proper
 maintenance  of  valves and  pumps  and  the ammonia recovery unit were  found  to
 have  negative  total  annual  costs.    In these cases,  the annual  by-product
 credits  were  large  enough to  more  than offset  the  total  annual   capital
 charges  and total  annual  operating  costs.   These items were, nevertheless,
 incorporated into the control cost totals.

 6-3.2 Sensitivity Analyses

      This  section  explores  the sensitivity of  the results to changes in/the
 engineering costs and economic assumptions.   In general, only  a single change
 from  the standard  economic assumptions was  made  in  each  case,  enabling the
 impact  of this  change  to  be  isolated.    Table. 6.3-7  summarizes  the  changes
 made  for each  case, while  Table  6.3-8 displays the fixed and  working  capital
 charge  rates  used to calculate  per-barrel control  costs.   Per-barrel pollu-
 tion  control  costs  for  all  case  studies,  expressed  as  a percentage  of a
 $36 per-barrel   upgraded   shale  oil   value,  are   given  in  Table'6.3-9.
 Table 6.3-10 provides  additional detail  for  the  absolute  per-barrel  control
 costs and  includes percentage changes  from the  standard  economic assumptions.
 Comparative results for Case Study A  for the  various sensitivity .analyses are
 presented  graphically  in Figures 6.3-1  and 6.3-2.  Each sensitivity analysis
 is discussed below.

      Twenty Percent Increase in Fixed Capital Costs—

      Cost  escalation  is always  a problem  with  pioneer plants  because of the
 numerous  uncertainties  (Merrow,  September 1978; Merrow, Chapel and Worthing,
 July  1979).  A  20%  increase is not at all unreasonable  despite the inclusion
 of a  20% contingency in the standard economic assumptions.

     Table 6.3-10 shows that the effect of  a  20%  increase  in fixed capital
 costs varies significantly  among  the control  groups.  Those that are capital-
 intensive  (such  as  retort gas treatment)  show  a  greater percentage increase
 (11-14%)  than  those that  are operating cost intensive  (such  as  solid waste
 management—only  4%).   Relative  to  results  under   the  standard  economic
 assumptions, the  increase  in  total  air  pollution control cost is 8 to 9%, or
 23  to 27  cents per  barrel.    The  percentage  increase in  the•; total water
 pollution  control cost  is  larger (14 to 16%), but the cost increase is quite
 small in  absolute  terms (2 cents per barrel).  These  results  indicate that,
 in aggregate, the pollution controls are not highly capital-intensive.

     Twenty Percent Increase in Operating  Costs—

     Operating  costs  are often  better  defined than capital costs,  which is
why  an  operating  cost contingency  is  not normally  included  in  the direct
annual operating costs.   However, there are many reasons why operating costs
could be higher than anticipated.  For example, regional shortages of skilled
 labor could  result in  higher wages  and reduced productivity.   Also,  labor
costs may escalate  faster than  other  costs.   Maintenance  costs could  be

                                '359                   :

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               TABLE 6.3-9.  SENSITIVITY ANALYSES EXPRESSED AS
                       A PERCENTAGE OF SHALE OIL VALUE

Per-barrel Control
Percent of $36/Barrel
Sensitivity Analysis
Standard Economic
Assumptions
+20% Fixed Capital Costs
+20% Direct Operating Costs
+66.7% Utilities Costs
80% of Planned Output
Delayed Start-up
15% DCF ROR
Stand-alone Financing
Ai
A, B
9.3
10.0
10.5
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11.0
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Shale

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as a
Oil Value
Solid Waste
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0.8.
0.8
0.9
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Stand-alone Financing
  at 15% DCF ROR

Combined Assumptions*

Combined Assumptions with
  Stand-alone Financing*
11.0    9.0    0.5   0.7   0.5        0.9

12.6   10.4    0.6   0.8   0.6        0.9
14.2   11.8    0.7   1.0   0.7
1.0
* Combined assumptions are 20% increase in fixed capital costs, 15% DCF ROR
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Source:   DRI.               .                    .
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higher  than  expected, and  both utility  requirements  and  utility unit costs
could deviate from expectations.

     The effect  of  a 20% increase in operating cost is, in general, somewhat
greater  than that  of the same-sized  increase in  capital  cost.   For  a 20%
increase,  although   air  pollution control  is only  increased  by 11  to 12%,
solid  waste  and  water  pollution  control  increase by  17% and  41  to 58%,
respectively.  The surprisingly large percentage increase for water pollution
control  occurs  because  under  standard  economic  assumptions  the  direct
operating  cost  is  only  slightly  larger  than the  by-product credit.   The
actual  increases  for water are only 6 or 7 cents per barrel compared with 33
to  44 cents  per  barrel   for  air  and  5  cents  per  barrel  for  solid waste,
however.

     Gas treatment  costs for  Case Study C increase by  only 8% (as compared
with 12% for Case Studies A and B)  due  to the less operating cost-intensive
nature  of  the  Stretford  gas treatment system used.  Comparing the results of
this analysis with  the results for  the  same-sized increase in fixed capital
costs confirms that the  water pollution  controls  and  solid waste management
are  very  operating  cost-intensive,  whereas  the  air pollution controls are
comparatively capital-intensive.

     86.7% Increase  in Utilities Costs—

     Operation of  various  controls  requires  inputs of  electricity,  steam,
fuel  gases  and  oil.  Under  standard  economic  assumptions,  electricity  is
valued  at  3  cents per kW-hr and it  is assumed that both steam and fuel gases
are purchased at a  price of $3/MMBtu.   The electricity charge of 3 cents per
kW-hr may very likely underestimate the true cost of purchased power from the
grid (should this prove necessary) as it is a compromise value between plants
that can sell  power and those that  must  purchase  power (see Section 6.1.1).
Since  the  TOSCO II  plant  is  likely  to require  electricity from  outside
sources, a 5 cents  per kW-hr rate (a 66.7% increase) was considered.  • At the
same time, steam and fuel gases prices were  also  increased by 66.7%, as the.
$3/MMBtu standard  rate for  these  inputs may also  prove  to be conservative.
Three dollars per million Btu is a typical 1980 value used for heat inputs in
engineering  studies,  but  no detailed cost evaluation was  conducted  for this
manual.  Hence,  both  the  steam  cost  and the  cost of  fuel  gases  must  be
considered uncertain.   Note,  however,  that  the costs of  fuel  oil  ($32/bbl)
and  cooling  water  were   not  changed,   as these  costs  are  subject  to less
uncertainty than electricity, steam and fuel  gases.

     The results  confirm  that utility  costs constitute  a  major Component of
pollution  control  costs.   For example,  particulate  and  miscellaneous  air
control costs increase by 81 cents  (a 45% increase).   This increase  largely
reflects the major  quantities of fuel  gases  used  to operate  the  thermal
oxidizers  for  shale  preheating.   Costs  for  other controls requiring large
inputs  of  steam  or  electricity also increase greatly.   Retort gas  treatment
costs  for  Case  Studies  A  and  B  increase 20% (due  largely to  steam,  fuel
gases,  and  electricity  required   to operate the  DEA unit  and Wellman-Lord
system).   The  66.7% increase in the cost of steam and, to  a  lesser  extent,
the 66.7%  increase  in the cost of electricity cause water pollution control

                                     371

-------
 costs  to increase by  14  to 15 cents  per barrel  (or 81 to 123%)  for all  three
 case  studies.   Steam  costs  make  up the major part of the operating costs  for
 the ammonia  recovery unit and foul  water strippers.
                         *  -     .         • '     •  '             '
     Overall  increases in  air pollution control  cost range from  34  to 35%,
 and  total control  costs  reach $3.67 to  $4.47 per barrel, with Case  Study C
 remaining the lowest  cost  option.   The total  water pollution  control cost
 ranges  from  27  to  32 cents per  barrel,  approximately  double  the cost  for
 standard-economic  assumptions.  These severe  increases in total  costs  suggest
 that  a more  accurate determination  of utilities  costs  would be  desirable.
 Solid  waste  management costs  are unaffected  by  an  increase  in  utilities
 costs.

     Eighty  Percent  of Planned Output—

     A  frequent problem  with  pioneer  process  plants is that  they fail   to
 achieve  their planned output.  Occasionally  they  produce more.  :When  a plant
 fails  to  ireach its planned  output, the fixed capital  charges must be spread
 over reduced output, and the  operating costs  decrease by a  lesser  proportion
 than the  output  because some  components  (such as maintenance) are  virtually
 unchanged.

     For  the case  of  a plant that achieves only  '80% of planned output, it  was
 assumed that direct  annual  operating  costs fall  to  90% of the full  production
 costs.  Production in  the  start-up years  and  by-product credits were prorated
 to 80% of the standard values.

     Overall,  the  results are moderately severe,  as the  solid waste manage-
 ment  cost increases  by  15% (4 cents  per  barrel) and retort  gks  treatment
 increases by 21 to 23  percent.  Total air pollution  control costs increase by.
 roughly  18%, or  50  to 62  cents  per  barrel,  with Case  Study  G  having  the
 lowest  cost  and  increase.   Total water pollution control  costs increase
 between 43 and 57%, or by 6  to 8 cents  per barrel.

     Delayed Start-up—

     Because  of   the  time-value  of  money  implicit  in  the  discounting
 procedure, anything that delays or curtails production  raises capital charges
 and, hence,  the  per-barrel  control cost; conversely,  anything that acceler-
 ates or extends production reduces the  costs.

     For  this  analysis, production is  halted for  two  years  (Years 2  and  3)
and then  follows  the  normal build-up profile displaced  by  two  years.  (The
project life  is  extended  by 2 years  to 22 years.)   This  profile corresponds
to  the  scenario  that  the  plant  initially   starts  production  according   to
schedule;  then,  at  the  end of  Year 1,  the  plant  is  closed  down because
serious operational  problems have developed and must  be  solved,;which takes
two years.

     The effects of  this  case are comparatively mild.  Total  costs increase
by about  8%  (22  to 26 cents per  barrel)  for  air pollution control and 13  to
16% (1 to  2  cents  per barrel) for water  pollution control.   Once again,  the


                                    372

-------
more capital-intensive control categories  (such as  retort gas treatment) show
the  largest  individual  increases.   Solid  waste management  shows only a tiny
increase  (1%)  because there  is very  little  capital  involved in solid waste
pollution control.

     Fifteen Percent DCF ROR—

     the  minimum acceptable  DCF  ROR use'd  in  a project feasibility study  is
normally-not  divulged  by  developers  and,  in any event,  is  influenced  by
alternative  investment  opportunities  and  other factors.   However,  there  is
broad  confirmation that ,a rate between  12 and  15% per annum  (in constant
dollars) is appropriate for evaluating oil  shale investments  (Denver Research
Institute.,  et  al.,  July 1979; also  see Merrow,  September  1978),   This ROR,
which  is  called  a  "hurdle rate,"  is  higher  than  the  return that a company
actually  earns  on  its  capital  for a  number of  reasons.   First,  it  is   an
unfortunate fact of life that many projects earn less than the projected rate
of  return  because things  do  not  work out  as  expected.  This is only partly
offset  by  the  few projects that do better  than anticipated.  Second, project
evaluations  do not usually  include  such  costs as  R  and D,  exploration, and
reserve  acquisition;  also,  they  may  not  include  recovery  of  some general
corporate expenses.

     The  single  most important  factor that  influences the required DCF ROR
is the  perceived riskiness of the project.   A high risk project is expected
to pass a  higher ROR hurdle  than  a  low risk  project.   Some  of  the types  of
risks  that  might be  subjectively taken into  account  in selecting a minimum
acceptable ROR for a mining project in the  U.S. include:

     *    Unproven technology (and, hence,  uncertain equipment costs);
     *    Geologic uncertainty;

     •  .  Very large investments in relationship to total corporate assets;
     •    Rapid inflation in some cost components;

     •    Long construction and start-up periods;
     *    Market uncertainty;

     •    Regulatory uncertainty (leading to delays or added costs); and
     •    Difficult working conditions or adverse socioeconomic impacts
          leading to manpower problems.


     For any first generation commercial synfuel  plant, all  the above factors
are present, with the possible  exception  of  geologic  uncertainty.   At this
time, most of  these  factors are strongly present in oil shale projects.  The
standard economic  assumption is  12%  DCF ROR, which  is probably  the  lowest
acceptable  return for  a  private  enterprise shale  oil  plant  with  proven
technology.   For a  pioneer plant,  industry   is  likely to  require  at  least
15% DCF.ROR,' unless  it  wishes to  "buy into"  a new industry.  Of  course,   if
another party  (e.g., the Federal  government)  were prepared to share the risk
in some way,  the  required ROR would  be  reduced.   Even though  , some  of the
risks  listed  above  do  not  apply  to pollution controls,  industry  does  not

                                     373

-------
perceive environmental costs to be separable from the entire project.  Hence,
all  components of  a  project,  including  pollution controls, must  earn the
specified DCF  ROR.

     Increasing the  required DCF  ROR from 12 to 15% has a moderate effect on
the  costs.   As expected, capital-intensive controls are those most affected:
for  example,  the  retort gas treatment costs rise by 14 to 18 percent.  Total
air  pollution  control  costs   increase  by  about  11% (31  to  36 cents  per
barrel).  Total  water pollution  control  costs  increase  by 21  to 26% (3 to
4 cents  per   barrel).   Solid  waste  management  costs  are  increased  only
slightly (by 5%, or 1 cent per barrel).

     Stand-alone Financing—               ,

     The term  "stand-alone  financing"  is used to describe a project in which
tax  credits  and allowances  for depreciation cannot  be passed  through  to a
parent  company  (or  companies)  which  can  benefit  from them  immediately.
(These benefits are treated as negative income tax  in conducting the alterna-
tive "pass-through"  form of project evaluation which  is  used under standard
economic assumptions.)   Instead,  it  is  necessary  for  the project to become
profitable  before  the  tax  benefits  can  be  obtained.   It  is  difficult to
determine when this  might occur because it requires  a detailed knowledge of
the  overall  project  economics;  in  any  event,  the  timing  of  the  benefits
will be affected by the selling price of the shale  oil.  However,;  it is known
that  some  of  the  developers  are assuming  stand-alone financing for their
evaluations  since  it  more  closely  reflects their tax positions than  does
pass-through financing.                                          <

     To  determine   the  approximate  effect   of   substituting   stand-alone
financing for  pass-through  financing,  it was assumed  that no  investment tax
credit or depreciation  could be claimed until the  third  year of production,
i.e.., the first year  of full output.   This assumption  was based on examina-
tion of the cash flow analysis for a room-and-piliar mine with surface retort
(of  unspecified technology)  presented  in a recent oil shale tax study (Peat,
Marwick, Mitchell  & Co.,  September 1980).   It must be emphasized that  this
assumption is very simplistic (and probably conservative), since the relevant
details, in the tax  study were significantly different  from  those assumed in
this manual.   The  overall  effect  is to increase total  air  pollution control
costs by only  about 5% (14 to 16  cents per barrel) and total  water pollution
control costs  by 9  to 11% (1 or 2 cents per barrel).   Solid waste management
costs were barely  changed.   A more refined calculation might yield  substan-
tially greater increases, especially if a low value was used  for the price of
shale oil,  thereby reducing profitability.

     The effect of  stand-alone  financing was also  evaluated  at;15%  DCF ROR,
using  the   same  assumptions  as  above.    This   probably  comes  closer to  a
developer's  evaluation.    In this  case,  the  increase  in  total  costs  is
significant,  ranging  from  51 to  59 cents per  barrel (18  to  19%)  for  air
pollution controls and  5 to 6. cents per barrel  (34 to 42%)  for water pollu-
tion controls.  Solid  waste  management costs again showed little  change,  up
by only 5.6%, or 2 cents per barrel.
                                     374

-------
     Combined Cases—

     Two  combined cases  were evaluated  using  the components  already dis-
cussed.  However,  it  is  not sufficient to construct these analyses by simply
combining  the  results   from  the  earlier  findings,  so  new  analyses  were
developed.  The two cases are as follows:

     Combined assumptions

     »    20% increase in fixed capital costs  _
     *•    Delayed start-up

     •    15% DCF ROR                                      .

     •'    Everything else as standard economic assumptions.

     Combined assumptions with stand-alone financing

     •-•    20% increase in fixed capital costs                       '     .

     »    Delayed start-up
     •    15% DCF ROR

     •    Stand-alone financing
     •    Everything else as standard economic assumptions.

     These combined cases  are intended to be quite plausible adverse scenar-
ios (i.e., 20%  increase  in fixed capital  costs and delayed  start-up) looked
at from  industry's viewpoint (i.e, 15% DCF ROR, with  or without stand-alone
financing, depending on the company).

     The  results  indicate that .these cases would  impose significant  burdens
on industry.   The most capital-intensive control group (retort gas treatment,
Case Study C) increases  in cost  by 62% for pass-through financing and by 93%
for stand-alone financing.  Water pollution control costs increase by greater
percentages,  but  as  explained earlier, this result  is  misleading because  of
the presence of a large,  unchanged by-product credit.

     Overall, the increase in total air pollution control cost ranges  from 36
to 38% for the  regular (pass-through) case and from 53 to 56% for the stand-
alone  case.   Water  pollution control  costs  rise from  64  to  78%  for the
regular case and 95 to 116% for the stand-alone case.  The smallest increases
are for  solid waste  management at 10 and 20%, respectively.   For the regular
(pass-through)  case,  the  absolute level  of  pollution control  costs ranges
from $3.75  to $4,55  per barrel  for  air  controls, 22  to  29 cents  for water
pollution control,  and  is  32 cents  per barrel  for solid waste management.
For  the  combined  assumptions with  stand-alone financing, absolute  control
costs are $4.25  to $5.13 for air,  26 to 35 cents for water,  and 35 cents per
barrel for solid waste.                      .
                                     375

-------
     Summary—                                                   !

     Returning  to  Table 6.3-9,   it  can  be  seen that  total  air pollution
control costs are roughly 8% of the assumed $36 per-barrel value for upgraded
shale  oil  under  the standard economic  assumptions.  Total  water pollution
control  costs are  roughly  0.4%  of  the value  of  the  oil   and  solid waste
management costs are 0.8 percent.                              .

     With respect to air pollution controls, only the utilities cost analysis
and the  combined assumptions  analyses produce major  increases in  cost.   A
66.7% increase in utilities costs increases total per-barrel   costs to between
10.2 and 12.4% of the shale oil value.  For combined assumptions, air control
costs increase to between 10.4 and 12.6% of the oil value^ while for combined
assumptions with  stand-alone financing,  the control costs range from 11.8 to
14.2%  of  the oil value.   In all  instances, Case  Study  C  remains  the lowest
cost option.

     Although much  smaller  than  air pollution control  costs, water pollution
control costs also   proved  to be quite  sensitive to  increases ,in utilities
costs.    The   66.7%  increase  in  utilities  costs  causes  water  control  costs
roughly to double and rise  to between 0.7  and 0.9% of  the  oil 'Value.   This
increase  can be  attributed to the  large  quantities  of  steam required for
ammonia recovery  and foul  water  stripping.   Case Study B  records the highest
water pollution  control  cost under the standard economic  assumptions and for
all of the sensitivity analyses,  due to the use of biological oxidation.  For
the combined  assumptions  with stand-alone financing, total control costs for
Case Study B increase  to 1.0% of  the  oil  value.   Water pollution control
costs for Case  Studies  A and C remain virtually identical, and reach 0.8% of
the shale oil value.

     Solid waste  management costs  show very,  little variance in response to
the sensitivity  analyses performed.   From  a  base  of  0.8%  of  the shale oil
value under  standard economic assumptions,  solid waste  costs rise no higher
than to 1.0% of  the oil value (for the combined assumptions with stand-alone
financing).    Solid  waste  management  costs are not capital cost-intensive and
are thus virtually unaffected by many of the sensitivity analyses.

     In no case  for any of the three media do the cost rankings ;change among
case studies; this  is  because there is very little  difference  among case
studies in the way  in  which the  costs are distributed  between1 capital and
operating components.           .

     Figures  6.3-1  and  6.3-2 split  the  pollution control costs  into a per-
barrel  total  capital charge  and  a per-barrel  total operating cost.   These
figures effectively illustrate the  response  of  capital-intensive  controls
(air)  vs.  operating cost-intensive  controls  (solid waste and  water)  to the
different .sensitivity analyses.
                                     376

-------
 6.4   DETAILS  OF  COST ANALYSIS METHODOLOGY

 6.4.1  Cost Algorithms

      This  section provides the  algorithms  used to calculate total  annual  and
 per-barrel control  costs  and  capital  charge factors.

      Calculation of Total  Annual  and  Per-barrel Control  Costs--

   ;   The total annual control  cost  (TC)  of  each item-considered  for pollution
 control  is the  sum of the  total  annual operating cost (TQC) and  the  total
 annual  capital charge (CC).   That is:

               TC  = TOC  + CC

      and       TOC  = DOC  + IOC

      where:       .   DOC  = Direct annual  operating cost
                     IOC  = Indirect annual  operating  cost

      and       CC  = (FCC  x RF) + (WC x  RW)

      where:          FCC = Fixed  capital  cost
                     WC  = Working  capital
                     RF  = Fixed  charge  factor
                     RW  = Working  capital  charge  factor


      The cost per barrel  (CPB) is the total annual  cost divided by  the normal
 annual production,  i.e.:                                         '.'-''

               CPB = TC -r  (BPSD x 328.5)

     where:          BPSD = Barrels per stream  day

The factor, 328.5,  is the  number of normal operating days per year.

     The derivation of each cost component is explained below.

     Direct annual operating cost.   DOC  is  a  data  input  derived  from the
engineering cost analysis.  It is  the  annual  cost for a normal  year and is
taken from one of the data Tables 6.1-1 through 6,1-4 or 6.2-3.

     Indirect annual operating cost.   The  indirect  annual  operating  cost
(IOC) is calculated as follows:

               IOC = TIA + ESC - STC - BP

     where:          TIA = Annual property tax and insurance allowance
                     ESC - Annual extra start-up costs (levelized—see below)
                     STC = Annual severance tax credit (levelized—see below)
                     BP   = Annual by-product credit

                                    377

-------
 BP is  an input generated from stream data and shown in one of the tables in
 Section 6.3,  and:

 •..'..'       TIA = 0,03 x FCC                          •.-.•[

                ESC = (0.03 x FCC + 0.20 x DOC) x LFAC1

                STC =0.04 x [(DOC + ESC + TIA - BP) + 0.05 x FCC] x LFAC2


     LFAC1  and LFAC2 are levelizing factors that spread ESC and STC uniformly
 over all  units of  production.   LFAC2 also makes adjustments for the severance
 tax  exemptions allowed  for low  production.   These  factors  are,  as  follows:


                               (1 + r)-1
           LFAC1 =.	•	
                    0.56  .    0.83    .   V20
                   .      +      ' \ o  +   y
                    0.56 +   .0.83    +  (1  +  r)~2  -  (1 + r)~20
                  1 +  r    (1 +  r)2              r
                = BPSD - 10,000    • .  .
                -     BpsD      x


       '  ' I v   0-83     1      1     + 3      1        (1 +  r)-4 ;-  (1  +  rr20
          4 x (1 + r)2.* 2 x (1 +»s + 4 x  (i +  r)4 +  *—        JT"      !—

                    0-56 ,   0.83     (x + r)-2 -  (i ^  ry-2Q
         .  '  '      1 + r   (1 + r)2             r                :


     where:          r = Discount rate = DCF ROR
                  BPSD = Barrels per stream day (i.e.,  normal daily output)

A  numerical  example of  a  levelizing calculation  is  given  in Section 6.4.3.

     Capital  costs.   Fixed capital  cost (FCC) is  an  input  taken'. from one of
the data tables.  Working capital (WC) is calculated as follows:

               WC = 1/12 x TOC + 1/4 x BP

     Capital  Charge Factors—                  '

     The fixed charge factor equation is:


                                     378

-------
               RF =
 N
 Z  Cd + r) n x (K  - T x Dn - C )]
n=J                n
          _    __   .__

  (1 - T)  I  [(1 + r) n 01
          n=l             n
     where:          Kn = Capital expenditure in year n (Z K  = 1.000)

                     C  = Investment credit in year n

  .                   0  = Depreciation in year n

                     0  = Operating income in year n (0  = 1.000 in a normal
                          year)                        n

                     r  = Discount Rate = DCF ROR
                     T  = Tax rate
                     N  = Last year of project

                     J  = First year of project (i.e., -3)

Note that the first year of production is Year 1.

     The same equation is used to determine the working capital Charge factor
(RW), except that the D  and C  terms are omitted.              :

6T4.2  Example Calculation of a Fixed Charge Factor

     Table 6.4-1  provides  an example  of the calculation  of a  fixed charge
factor.   The  data  used  are  for  retort  timing,  using  standard  economic
assumptions (see Table 6.2-2).

     the  following  is  an  explanation  of  the  calculations  ini the  table.
Expenditures are  shown negative, while  income (and taxes  avoided)  is  shown
positive.  Column [2] is a schedule of capital expenditures to be made over a
three-year period, totaling an arbitrary $1,000.   (Unit value is used instead
of  $1,000  in  the equation  above.)   Columns [3],  [4],  and  [5] deal  with
allowances  associated  with  this  capital  expenditure.    Column [3]  is  a
schedule of depreciation, commencing  in  Year 1 when the asset is placed into
service.    Column  [4]  gives  the  value  of the depreciation allowed to  the
company.   This value  is  the income tax  not  incurred  as a consequence of the
depreciation deduction, and  it  is 48% of  Column  [3].   Column  [5]  is the 20%
investment tax credit  available  in  each year a capital  expenditure  is  made.
(This  is a direct credit against tax  and  does  not have to  be  multiplied by
the tax rate.)

    .Column [6]  represents   the  income  stream   resulting   from  the  $1,000
investment  (Column [2]).    Income  in  a  normal,   full  production  year  is
designated  by  "l.OOx."   Since  income  is proportional  to production,  and
production in the  start-up  years  is less than full  production, the first two

                                     379

-------
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 years of income are appropriately reduced, i.e., 0.56x in Year 1 (0.56 is the
 50% operating factor  in  Year 1 divided by the  90% factor for a normal year)
 and 0.83x  in Year 2,  Column [7]  shows  the  residual  income to  the company
 after income tax is paid on the income in Column [6].

      The 12% discount  factors in Column [8] are used to generate the present
 values in  Columns  [9], [10],  [11]  and [12].   After  summing the  columns  of
 present values  of  after- tax  income,  depreciation allowance,  investment tax
 credit, and capital  expenditure,  an equation is constructed to determine the
 gross income, x, which must be generated by the $1,000 of invested capital  to
 achieve a 12% DCF ROR; thus:

                3.6093X = 1,061.44 -  265.48 -  212.29

                  [9]   =   [12]   -   [10]   -   [11]              .
      therefore:      x  =          =  161.71
      (x  represents  the  gross  income  in  a  full  production year  that  is
      necessary to  provide  the  specified  DCF ROR,  12%, on  $1,000 of  fixed
      capital.)
      hence:     RF = -       = 16.17%
 6.4.3  Cost Levelizing  Calculations

      While  most direct operating costs  vary  in proportion to plant  output,
 the  operating  costs  for solid waste  management  do  not.   For example, the  cost
 of the  spring  collection system  starts  in Year  0 and  finishes  in  Year  14.  To
 spread  these costs  in  a pattern consistent with production, these operating
.costs are transformed into  an annual 'figure which  can then  be  applied  to  each
 barrel  of shale  oil  produced.  This  is  done by  calculating  a "levelized cost"
 for  a  normal  year's production.  This technique  is  also used to spread  the
 extra  start-up  cost  and  severance tax  credit  uniformly  over  shale   oil
 production.

      A  "levelizing  factor"  is used  to  make this transformation.  The  follow*
 ing  equation shows  how  a levelizing factor is  used  to  arrive at a levelized
 cost (i.e., a  stream   of  payments  having the   same  profile as  production),
 given the present value of  a nonuniform stream  of  payments:


               uvemed Cost'-


 By dividing the levelized cost  by a normal year1s output,  a cost per  unit of
 production  is  derived.

                     '               381                      .   '    ' '      .

-------
      The equation for calculating the 1 eve1izing factor (LF)  is:


                LF=PVFA(r,N)   *   j^VF^n)  x [l-Ln])


      where:           LF  = Levelizing factor

                      PVFAfy,  N,  =  Present value  factor  of  a  uniform series  of
                                  payments for N years

                      PVfV»- n^   =  Present value  factor  of  a  single  payment  in
                         V'nj.     year n                             '

                      r   = Discount Rate  = DCF ROR       .         ,

                      N   = Number  of production  years

                      S   = Number  of years in the start-up period

                      n   = Any specific year in  the  start-up period

                      Ln  = The proportion of normal  output during any given
                           start-up  year;  the series of  L  values constitutes
                           the "start-up  profile"

      The  second  term on  the   right-hand side   of  the above  equation  is  an
adjustment  to  the   uniform ,series  represented  by  the  first   term.   The
complement of  the L  figure (i.e.,  that portion of each start-up year which
is less than full production) is  discounted, summed, and  then  subtracted from
the uniform 'series.   Since the start-up  years  have high  present  values, the
effect  of subtracting this, term  has a  substantial  impact  on the Tevelizing
factor.   Because  the  levelizing  factor  is  the denominator  in  the equation
which determines the  levelized cost  (and,  hence, the unit cost), this adjust-
ment  term raises the  per-barrel cost.

      Cost LevelIzing  Example—

     To illustrate the concept of cost levelization, a calculation of the 12%
DCF ROR levelizing factor used for this manual  is presented below:

     Year     % of Maximum Output (Ln)    PVF @  12%          (1-L ) x PVF

      1                  56               0.8929               0.3929
      2                  83               0.7972               0.1355
      3                 100     \                             o.;oooo

                                          5.7793                  !


     20                 100       '    .	               O.OQOQ
                                          7.4694           .    0.5284

     Hence:     LF(r=12%}  ^ yrs) = 7.4694 - 0.5284 = 6.9410

(Note that all  present values are  expressed with respect to  Year 0..)


                                     382

-------
      This factor is the same as the denominator in the levelizirig expressions
 LFAC1 and LFAC2.
      As an illustration of a levelizing calculation, consider the groundwater
 collection costs.*  These costs are incurred as follows:
                Year 0:          $6,270
                Years 1 to 14:   $12,375/yr
      The present value of  these  costs,  expressed with respect  to  Year 0,  is
 calculated as follows:
           Year
                Expenditure
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
6,270
12,375
12,375
12,375
12,375
12,375
12,375
12,375
12,375
12,375
12,373
12,375
12,375
12,375
12,375
PVF @" 12%

 1.0000
 0.8929
 0.7972
 0.7118
 0.6355
 0. 56.74
 0.5066
 0.4523
 0.4039
 0.3606
 0.3220
 0.2875
 0.2567
 0.2292
 0.2046
Present Values
     Thus,  $88,294  is the  present value  of all the  groundwater collection
costs.  To  turn  this  into a cost  that  is distributed uniformly with respect
to output, it must be divided by LF(r = ^ N = 2Q years)<
Therefore, Level i zed Cost =
                                        = $12,721
* These  costs  are  specified here  with  greater precision  than is  shown in
  Table 6.1-5.
                                     383

-------
     Thus, $12,721  (rounded  to $13,000 in Table 6.2-3) is the annual cost in
a  normal  production year  that is  equivalent  to the  irregular cost profile
given  above.   This direct  annual  operating cost can  be  used in conjunction
with the  algorithms given  in Section 6.4.1 for calculation  of total  annual
control cost  and per-barrel  control  cost, whereas  the irregular  stream of
expenditures  from  which it was  derived  could not be  used with, the standard
methodology.

     In summary,  cost levelization  redistributes  a cost series  that  is not
proportional   to  production in  such a way  as  to yield an equivalent  series
that is proportional to production and has the same economic  value.
                                    384

-------
                                   SECTION 7

                      DATA LIMITATIONS AND RESEARCH NEEDS


      A  number  of  limitations  associated  with  stream  characterization  and
 pollution  control  technology performance  were identified  in  the data  base
 during  the  preparation  of  the  Pollution Control Technical  Manual  for  the
 TOSCO II oil  shale  retorting  process  combined  with underground  mining.   It is
 important  that users  of this  manual  be  aware  of these limitations.   It is
 also  important  that these limitations  be addressed prior to  development  of an
,oil  shale  facility of  the magnitude  analyzed  in this manual and  proposed by
 Colony   Development  Operation   (e.g.,   66,000 TPSD   oil  shale  mined   and
 47,000  BPSD  upgraded  shale oil  produced).

 7.1   DATA  LIMITATIONS

      The   description   of the  TOSCO  II  retorting  process   and  information
 regarding  applicable  control  technologies,  performance, and  costs  used  to
 prepare  this  manual   were  obtained   from   reports  on  the   operation   of
 experimental   TOSCO II   retorts,   vendor  descriptions,   and   engineering
 calculations  used  in  conjunction with  experience  transferred  from  analogue
 industries  such  as the  petroleum,   utility,  and  mineral  mining industries
 which utilize similar  control  technologies.   Until  "hands  on"  experience  is
 obtained from commercial-scale  oil shale operations, these sources constitute
 the  best  available  data base.    However,  the  limitations of this data base
 should  be  clearly  understood.  Experimental retorts  were built and  operated
 primarily  to improve process design and not for  demonstrating  operation of a
 commercial-sized  retort with  attendant  pollution  control  systems.   Many
 pollution  control  systems  have  never been pilot  tested with  an oil   shale
 retort.   Even for  those .control   systems  that were pilot  tested, often  the
 data  collected have been very limited.                           :

     The primary  experience with TOSCO II retorting  involves  a pilot plant
 (24 tons/day)  and  a  semi-works  plant (1,000  tons/day)  operated in  Colorado
 over  the  past  several  years,  and the available  data  from  these tests have
 been  used   in this manual.   A  full-sized  TOSCO II  retort  is  expected   to
 process 11,000 TPSD of raw shale, and six of  these retorts will :be needed  to
 produce  47,000 BPSD  of  upgraded shale  oil.   This  represents  an   enormous
 scale-up of  the  pilot and semi-works  retorts; therefore, improvements in  the
 retort design and operating  parameters may be inevitable,  resulting  in some
 uncertainty   about   the  stream  compositions  and  performance  of  control
 technologies.

     Variations in  the grade of the shale also introduce modifications to  the
 operating parameters and, hence,  the data.  The TOSCO II experimental  retorts


                                     385

-------
 have  been  operated on  a site-specific basis,  i.e.,  primarily with shale mined
 from  the  site  of  the  prospective development  (the Colony  property  near
 Parachute,   Colorado).    A   linear  extrapolation   of  the   data   from  these
 operations  may not be entirely applicable to  the processing of  shales  from
 other locations (e.g., Tosco Corporation's Sand Wash project in  Utah),  and  a
 direct  transfer of the  information  to  other development sites -.must  be  made
 with  caution.

      It  should also  be  noted  that,   to  date,  the  TOSCO II  plants  have
 primarily  consisted  of  the pyrolysis   system;  that  is,   only  the  preheat
 system,  retort, and overhead  fractionater  have been  included^  Other  unit
 processes  (e.g.,  oil and gas recovery,  hydrogen unit,  hydrotreaters,  delayed
 coker)  and control technologies (e.g.,  sulfur  recovery,  tail gas treatment,
 ammonia  recovery)  that  form  the basis for the complete  plant analyzed  in  this
 manual have  not yet been  tested with the  TOSCO  II process (with the exception
 of  the   diethanolamine  acid  gas   removal  process   which was  tested in
 conjunction  with  the pilot plant, but performance  data from the  test  are not
 available).     Therefore,    actual    control    technology    performance   and
 compatibility with  the  TOSCO  II retorting process have  not been demonstrated.

      The  fact  that the  processing  streams  have  been measured  in  terms of
 major constituents only  is  an  additional  limitation.   Information  on minor
 constituents,  which may  be  of concern  from  an  operational as  well  as an
 environmental   viewpoint,  is  not   well  documented.   Examples  of   such
 constituents  include   regulated  and  nonregulated  pollutants  (e.g.,  trace
 elements,  specific organics, inorganics),  all  of  which  can have an  impact
 upon  the choice and operation of downstream control.

      Assessing  the  limitations  of  existing  data  sources   was  an important
 by-product  resulting from the  preparation  of  this manual.   Since  the  best
 available  information  on each  subject was selected,  this  manual represents
 the best currently  available data  base  on  the TOSCO  II retorting  process;
 also, within  the  limitations of available data, it accurately estimates the
 control efficiencies achievable.

 7.2   RESEARCH NEEDS

      The limited potential  for  the  transfer of control technology from pilot
 and semi-works retorting tests and from analogue industries  to commercial oil
 shale operations emphasizes  a genuine need for research  in  certain  areas of
 oil shale processing and pollution control.   This need  is strengthened by the
 fact  that, even with several years  of experience,  the oil  shale industry is
 still  in an early state of development.

     While it  is  recognized  that  further research will be  essential  in all
phases of  oil  shale commercialization,  the major  areas  of  data  uncertainty
 regarding characterization of streams and control  technology performance, as
revealed  during  preparation   of   the  TOSCO II  PCTM,  are  identified  in
Table 7.1-1.   The  status  of  the  information  is presented  according  to  the
development  stage   of  the source  and technology.   The specific  information
sources are also identified.   A  reliability or confidence ranking is  assigned
to the data  for each stream and technology based  on a subjective evaluation

                                ;  .   386                         :

-------
of  the  direct applicability  of  the  data to  a commercial-scale  TOSCO II
facility.   Some  salient  features and  caveats  in  the information  base  are
noted, and  specific research  needs  are  identified  to overcome  some  of  the
data limitations.
                                    387

-------
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                                             388

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Approximately 95% of the organic
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waters is not documented. In this
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The operating experience with oil
shale process waters is not docu-
mented. The technology is used
commercially in other industries.
The Phosam-W process was examined. i
this manual as an example of an
ammonia recovery process. Over 993!
of the ammonia in the sour water ca
be recovered by this technology.

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                                   SECTION 8

                                   REFERENCES


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 American  Petroleum Institute.  1969.  Manual  on Disposal  of Refinery Wastes,
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 American  Petroleum Institute.   March 1978.   A New Correlation of NH3, C02 and
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 Barduhn,  A.J.   September  1967.   The Freezing Processes for  Desalting Saline
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 Battelle,  Columbus Laboratories.   October 1978.   Control  of NOx  Emission  by
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 Beychok, M.R.  1967.   Aqueous Wastes  from Petroleum and Petrochemical  Plants.
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 Calmon, C.  and  H.  Gold.    1979.   Ion  Exchange for  Pollution Control.   2  vols.
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 Cheremisinoff,  P.N.  and F.  Ellerbusch.   1978.   Carbon Adsorption Handbook.
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 Coffin, D.L., et al.   1968.  Geohydrologic Data  from the Piceance  Creek  Basin
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Colony Development Operation.   1974.   An Environmental Impact Analysis  for a
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                       ' . *•'
Colony  Development Operation.  1977.   Prevention  of  Significant Deteriora-
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-------
Colony   Development  Operation.    January  26,  1979.    Correspondence  to
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Colony  Development Operation.   March  1980.   Application  to  Colorado Mined
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Colorado  Mined  Land   Reclamation   Board.   October  23,  1980.    Solid  Waste
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Denver  Research  Institute/Water  Purification  Associates/Stone  and  Webster
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     Report No. COO-5107-2.                                     ;

Oravo  Corporation.   1975.   Materials  Heading  Techniques  for  Backfilling a
     Proposed Oil Shale Mine.

Dravo  Corporation.  February 1976.  Handbook of  Gasifiers  and Gas Treatment
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Electric' Power Research  Institute.   April 1980.  Economic and Design Factors
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Fox, J.P. ,  D.E.  Jackson  and  R.H.  Sakaji.   1980.   Potential Uses  of Spent
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Fox, J.P.,  K.K.  Mason  and J.J. Duvall.  1979.   Partitioning of Major, Minor
     and Trace Elements  During Simulated  In  Situ Oil  Shale Retorting.   12th
     Oil  Shale  Symposium  Proceedings,  Colorado  School  of Mines,  Golden,
     Colorado.                                                   ,

Girvin,  D.C. ,  T.  Hadeishi  and J.P. Fox.   June 1980.   Use  of Zeeman Atomic
     Absorption  Spectroscopy  for  the  Measurement  of  Mercury in  Oil  Shale
     Gases.   Oil Shale  Symposium:   Sampling, Analysis and Quality Assurance,
     March 26-28,  1979,  Denver, Colorado.   EPA-600/9-80-022.   U.S. Environ-
     mental  Protection Agency.

Haas,  F.C.   June 1979.   Analysis  of TOSCO II Oil  Shale Retort Water.   Pre-
 •    sehted at American  Society for Testing  and  Materials  Symposium  D-19 on
     Analysis  of   Waters  Associated   with  Alternative  Fuel   Production,
     Pittsburgh,  Pennsylvania.  ASTM STP 720.

Hart, J.A.  June 11, 1973.   Waste  Water Recycled for Use in Refinery Cooling
     Towers.  Oil and Gas Journal.   71(24):92-96.

Hicks,   R.E.,  et al.   June 1979.   Wastewater Treatment  in  Coal  Conversion.
     EPA-600/7-79-133.   U.S. Environmental Protection Agency.
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-------
 Hicks,  R.E.  and  L  Liang.   January  1981.   A  Study  of Reverse  Osmosis for
      Treating Oil  Shale In Situ Wastewaters,  Final  Report.  . DOE/LC/10089-S.
      U.S.  Department of Energy.

 Hicks, R.E. and  I.E.  Wei.   December 1980.  A  Study of Aerobic Oxidation and
      Allied Treatments  for  Upgrading  In Situ  Retort Waters,  Final  Report.
      DOE/LC 10097-1.   U.S.  Department of Energy.

 Humenick,   M.J.   1977.   Water  and  Wastewater  Treatment:    Calculations  for
      Chemical  and Physical  Processes.   Marcel  Dekker,  New York.

 Jones, B.M.,  R.H. Sakaji and C.G.  Daughton.    August  1982.   Physicochemical
     .Treatment Methods   for  Oil  Shale  Wastewater:   Evaluation  as Aids  to
      Biooxidation.   15th Oil  Shale Symposium  Proceedings,  Colorado School  of
      Mines,  Golden,  Colorado.

 Kohl,  A.L.  and  F.C,  Riesenfeld.   1979.   Gas  Purification.   3rd  ed.   Gulf
      Publishing Company,  Houston, Texas.

 Krisher,  A.S.   August  28,  1978.  Raw Water Treatment in the CPI.   Chemical
      Engineering.  85(19): 78-98-                                 '.'

 Maddox,  R.N.   April  1977.    Gas and  Liquid  Sweetening.   Campbell  Petroleum
      Series, 2nd  ed.   J.M. Campbell, Norman, Oklahoma.           :

 McWhorter,  D.B.    1980.   Reconnaissance  Study of  Leachate  Quality from Raw
      Mined  Oil Shale—Laboratory Columns.   EPA-600/7-80-181.   U.S.  Environ-
      mental  Protection Agency.

 Mercer,  B.W.,  A.C.  Campbell  and W. Wakayima.   May 1979.  Evaluation of Land
      Disposal  and Underground Injection  of  Shale Oil  Wastewaters.   U.S. De-
      partment  of  Energy Report No. PNL-2596.

 Merrow,  E.W.   September  1978.   Constraints on  the Commercialization of Oil
      Shale.  R-2293-DOE.  U.S. Department  of Energy.

 Merrow,  E.W. ,  S.W.  Chapel  and  C.  Worthing.   July  1979.   A  Review of  Cost
     Estimation in New Technologies:   Implications  for Energy Process Plants.
     R-2481-DOE.  U.S. Department of Energy.

Metcalf  &  Eddy  Engineers.    October 1975.   Water  Pollution  Potential   from
     Surface  Disposal  of Processed  Oil  Shale  from  the TOSCO II Process,
     Vol. I.   Report  prepared for Colony  Development  Operation and Atlantic
     Richfield Company (Operator).

Mutter, J.  and C.  Waitman.  1978.  Oil Shale Economics Update.  Tosco Corpor-
     ation, Los Angeles, California.

Peabody Process Systems,  Inc.   February 1981.    Paid study on suitability of
     the  Holmes-Stretford Process  for  Oil  Shale  Projects.   Prepared for
     Denver Research Institute, Denver, Colorado.
                                     407

-------
 Pearce,   R. L.   1978.   Hydrogen  Sulfide  Removal  with  Methyldiethanolamine.
      Proceedings   of  57th  Annual  Convention,  Gas. Producer's  Association,
      New Orleans,  Louisiana.

 Peat,  Warwick,  Mitchell '&  Co.   September 1980.   Final  Report:   Oil Shale Tax
      Stgdy.   Prepared for  the  Committee  on Oil  Shale,  Rocky Mountain Oil and
      Gas.Association.   Washington.,  D.C..

 Peters,  M.S.  and K.D.  Timmerhaus.   1980.   Plant  Design  and  Economics  for
      Chemical  Engineers.   3rd ed.   McGraw-Hill.

 Peterson,  R.W.,  F.C. Townsend  and  R.A. Bloomfield.   November 1978.  Geotech-
      nical  Properties  of  a  Fine-Grained  Spent  Shale Waste,   lith Oil  Shale
      Symposium  Proceedings,   Colorado School  of  Mines,  Golden,  Colorado.

 Pforzheimer,  H.  and S.K. Kunchal.  March 24,  1977.   Commercial Evaluation of
      an  Oil  Shale Industry Based on  the  Paraho Process.   Paper presented to
      the  American  Chemical Society National Meeting, New Orleans, Louisiana.

 Prien, C.H.  and T.D. Sevens.   March  1977.   An Engineering  Analysis Report on
      the  TOSCO II  Oil Shale  Process.   Prepared  by Denver  Research Institute
      and TRW, Inc. for  U.S.  Environmental  Protection Agency.

 Pritchard  Corporation.    September  14,  1981.   Communication  with Stone  and
     Webster Engineering Corporation,  Denver,  Colorado,  regarding information
     on Glaus and SCOT  processes.

 Rangnow, D.G. and P.A.  Fasullo.  September 28, 1981.  Rapid Growth is  Outlook
     for Recovered Sulfur.  Oil  and Gas Journal.  79(39):242-246.

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 Resources  Conservation  Corporation.    September  1981.   Communication   with
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                                     408

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Uhl,  V.W.    June  1979.   A Standard Procedure for Cost Analysis of  Pollution
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U.S. Department of the  Interior, Bureau  of Land Management.   1977.    Final
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U.S. Environmental  Protection  Agency.   January  1975.   Sulfur Oxides Control
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     EPA 600/2-75-006.                    .                      '

U.S. Environmental Protection Agency.   July 11, 1979.  Prevention of Signif-
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U.S. Environmental  Protection  Agency.   September  1980.    Lining   of   Waste
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U.S.S.  Engineers and Consultants, Inc.  April 1978.  Communication with  Water
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